$9,900,600 South Carolina Public Service Authority

Transcription

1 NEW ISSUE In the opinion of Bond Counsel, assuming continued compliance by the Authority with certain covenants, interest on the 2006M Bonds is excludable from gross income for federal income tax purposes under existing statutes, regulations and judicial decisions. Interest on the 2006M Bonds is not an item of tax preference in computing the alternative minimum taxable income of individuals or corporations. Interest on the 2006M Bonds will, however, be included in the computation of certain taxes including alternative minimum tax for corporations. See TAX MATTERS for a description of alternative minimum tax treatment and certain other federal income tax consequences to certain recipients of interest on the 2006M Bonds. The 2006M Bonds and the interest thereon will be exempt from all State, county, municipal and school district and other taxes or assessments imposed within the State of South Carolina, except estate, transfer and certain franchise taxes. $9,900,600 South Carolina Public Service Authority Dated: October 20, 2006 Revenue Obligations, 2006 Series M Consisting of $2,638, % Current Interest Bearing Bonds Due January 1, 2013 $2,524, % Current Interest Bearing Bonds Due January 1, 2018 $2,105, % Current Interest Bearing Bonds Due January 1, 2023 $1,589, % Capital Appreciation Bonds Due January 1, 2018 $1,042, % Capital Appreciation Bonds Due January 1, 2023 The Revenue Obligations, 2006 Series M (the 2006M Bonds ) will be sold directly by the South Carolina Public Service Authority (the Authority ) only to residents of the State of South Carolina (the State ), customers of the Authority, members of electric cooperatives organized and existing under the laws of the State, and electric customers of the City of Bamberg, South Carolina and the City of Georgetown, South Carolina. The Current Interest Bearing Bonds will be issued in registered form in denominations of $500 or integral multiples thereof. The Capital Appreciation Bonds will be issued in registered form in denominations of $200 original principal amount or integral multiples thereof. The 2006M Bonds will be sold by the Authority directly to investors. The maximum amount of 2006M Bonds, as measured by the initial purchase price thereof, which may be initially purchased by one investor shall be $10,000 as described herein. Any 2006M Bonds will be purchased by the Authority on demand by the owner thereof upon the terms and conditions set forth herein. The Authority s obligation to redeem the 2006M Bonds at the election of the Bondholders is limited to 5% of the original issue amount of the 2006M Bonds in any calendar year. Interest on the Current Interest Bearing Bonds, payable on January 1 and July 1 of each year, commencing July 1, 2007 (251 days of interest) will be mailed by check or draft mailed to the registered owners thereof. Interest on the Capital Appreciation Bonds will be compounded semiannually and payable only upon maturity or earlier redemption or elective purchase thereof. The maturing principal of the Current Interest Bearing Bonds and the maturing principal and interest of the Capital Appreciation Bonds will be payable at the principal office of The Bank of New York Trust Company, N.A. (the Trustee ). The 2006M Bonds will be subject to redemption at the option of the Authority prior to maturity on and after January 1, 2007, as set forth herein. The 2006M Bonds are payable solely from, and secured by a lien upon and pledge of, the Revenues and moneys in the Revenue Fund of the South Carolina Public Service Authority (the Authority ) on a parity with the lien and pledge securing Revenue Obligations heretofore and hereafter issued pursuant to the Revenue Obligation Resolution, but junior, subordinate and inferior to the lien and pledge of Revenues securing certain bonds heretofore and hereafter issued. The 2006M Bonds are being issued to fund a portion of the cost of the Authority s ongoing capital improvement program. See CAPITAL IMPROVEMENT PROGRAM. The 2006M Bonds are not debts of the State of South Carolina (the State ), nor of any political subdivision thereof, and neither the State nor any of its political subdivisions shall be liable thereon, nor shall they be payable from any funds other than the Revenues of the Authority pledged to the payment thereof. The 2006M Bonds are offered when, as and if issued subject to the approval by legality by Haynsworth Sinkler Boyd, P.A., Charleston, South Carolina, Bond Counsel. It is expected that the 2006M Bonds will be available for delivery by the Trustee to the initial holders thereof within 45 days of the sale date. November 15, 2006

2 SOUTH CAROLINA PUBLIC SERVICE AUTHORITY One Riverwood Drive Moncks Corner, South Carolina (843) ADVISORY BOARD Governor MARK SANFORD Attorney General HENRY MCMASTER State Treasurer GRADY L. PATTERSON, Jr. Comptroller General RICHARD ECKSTROM Secretary of State MARK HAMMOND DIRECTORS O. L. THOMPSON, Chairman JOHN T. MOLNAR G. DIAL DUBOSE, First Vice-Chairman JAMES W. SANDERS,SR. CLARENCE DAVIS, Second Vice-Chairman DAVID A. SPRINGS PAUL G. CAMPBELL WILLIAM A. FINN J. CALHOUN LAND,IV CECIL E. VIVERETTE BARRY D. WYNN EXECUTIVE MANAGEMENT LONNIE N. CARTER... BILL MCCALL,JR.... ELAINE G. PETERSON... JAMES E. BROGDON,JR.... RENNIE M. SINGLETARY III... PRESIDENT AND CHIEF EXECUTIVE OFFICER EXECUTIVE VICE PRESIDENT AND CHIEF OPERATING OFFICER EXECUTIVE VICE PRESIDENT AND CHIEF FINANCIAL OFFICER SENIOR VICE PRESIDENT AND GENERAL COUNSEL SENIOR VICE PRESIDENT, CORPORATE SERVICES Revenue Obligation Fund Trustee The Bank of New York Trust Company, N.A. Revenue Bond Fund Trustee US Bank, National Association Haynsworth Sinkler Boyd, P.A. Lehman Brothers TRUSTEES BOND COUNSEL FINANCIAL ADVISOR Jacksonville, Florida Columbia, South Carolina Charleston, South Carolina New York, New York

3 No dealer, broker, salesman or other person has been authorized by the Authority to give any information or to make any representations with respect to the 2006M Bonds other than the information and representations contained in this Official Statement, and, if given or made, such other information or representations may not be relied upon as having been authorized by the Authority. This Official Statement does not constitute an offer to sell or the solicitation of an offer to buy nor shall there be any sale of the 2006M Bonds by any person in any jurisdiction in which it is unlawful for such person to make such offer, solicitation or sale. The information set forth herein has been provided by the Authority and other sources which are believed to be reliable. The information and expressions of opinion herein are subject to change without notice and neither the delivery of this Official Statement nor any sale made hereunder shall, under any circumstances, create any implication that there has been no change in the matters described herein since the date hereof. NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES COMMISSION HAS APPROVED OR DISAPPROVED OF THE 2006M BONDS OR PASSED UPON THE ADEQUACY OR ACCURACY OF THIS OFFICIAL STATEMENT. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE. INTRODUCTION... 1 General... 1 The Authority... 1 Authorization of 2006M Bonds... 1 Other Indebtedness of the Authority... 2 Purpose of the 2006M Bonds... 2 DESCRIPTION OF THE CURRENT INTEREST BEARING BONDS... 2 General... 2 Redemption... 2 Purchase of Current Interest Bearing Bonds by Authority... 3 DESCRIPTION OF THE CAPITAL APPRECIATION BONDS... 3 General... 3 Redemption... 3 Purchase of Capital Appreciation Bonds by Authority... 4 Accreted Value Table for Bonds Maturing January 1, Accreted Value Table for Bonds Maturing January 1, TABLE OF CONTENTS Page Page Landfill Sites General Improvements Regional Water Systems COMPETITION The Electric Utility Industry Generally Changes in Federal Regulation of Electric Utilities Regional Transmission Organizations REGULATORY MATTERS FERC Matters Environmental Matters Nuclear Matters LITIGATION AND OTHER MATTERS Litigation Other Matters FINANCIAL ADVISOR DEBT SERVICE SCHEDULE... 8 SECURITY FOR THE 2006M BONDS... 9 General... 9 Rate Covenant... 9 Additional Indebtedness Lease Fund Payments Commercial Paper Notes and Revolving Credit Agreement Capital Improvement Fund Requirement ORGANIZATION AND MANAGEMENT OF THE AUTHORITY CUSTOMER BASE Service Area Wholesale Direct Retail Service Area Large Industrial Contracts TAX MATTERS Federal Income Tax Generally Collateral Federal Tax Considerations State Tax Exemption APPROVAL OF LEGAL PROCEEDINGS MISCELLANEOUS APPENDICES COMPANY S FINANCIAL STATEMENTS... I SUMMARY OF CERTAIN PROVISIONS OF THE REVENUE OBLIGATION RESOLUTION... II FORM OF OPINION OF HAYNSWORTH SINKLER BOYD, P.A.... III POWER SUPPLY AND POWER MARKETING Generating Facilities Power Resources Transmission Interconnections and Interchanges Reliability Agreements Distribution General Plant Fuel Supply Fuel Costs The Energy Authority Coelectric Partners RATES AND RATE COMPARISON Rates Rate Comparison HISTORICAL SALES Historical Demand, Sales and Revenues FINANCIAL INFORMATION Historical Operating Results CAPITAL IMPROVEMENT PROGRAM General Long-Term Power Supply Plan Cross Unit Cross Unit Pee Dee Unit Future Nuclear Unit... 27

4 [THIS PAGE INTENTIONALLY LEFT BLANK)

5 OFFICIAL STATEMENT relating to $9,900,600 South Carolina Public Service Authority General Revenue Obligations, 2006 Series M Consisting of $2,638, % Current Interest Bearing Bonds Due January 1, 2013 $2,524, % Current Interest Bearing Bonds Due January 1, 2018 $2,105, % Current Interest Bearing Bonds Due January 1, 2023 $1,589, % Capital Appreciation Bonds Due January 1, 2018 $1,042, % Capital Appreciation Bonds Due January 1, 2023 INTRODUCTION The purpose of this Official Statement is to set forth information concerning the South Carolina Public Service Authority (the Authority ) Revenue Obligations, 2006 Series M (the 2006M Bonds ) offered hereby. All of the summaries of the Revenue Bond Resolution and Revenue Obligation Resolution (hereinafter defined) herein contained are made subject to all of the provisions of such documents, and such summaries do not purport to be complete statements of such provisions. Reference is hereby made to such documents for further information in connection therewith. Copies of such documents may be examined at the main office of the Authority in Moncks Corner, South Carolina, and at the office of Haynsworth Sinkler Boyd, P.A., Charleston, South Carolina. The REPORT OF COMPANY S FINANCIAL STATEMENTS is attached as Appendix I to this Official Statement. Defined terms not herein defined are defined in Appendix II -- SUMMARY OF CERTAIN PROVISIONS OF THE REVENUE OBLIGATION RESOLUTION. The Authority The Authority is a body corporate and politic created by Act No. 887 of the Acts of the State of South Carolina (the State ) for 1934 and acts supplemental thereto and amendatory thereof (Code of Laws of South Carolina 1976, as amended -- Sections through ) (the Act ), which, among other things, authorizes the Authority to produce, distribute and sell electric power and to acquire, treat, transmit, distribute and sell water at wholesale. The Authority began electric power operations in The commercial operation of the regional water system began in October Authorization of 2006M Bonds The 2006M Bonds are issued pursuant to a resolution adopted by the Authority's Board of Directors on April 26, 1999, as amended and supplemented from time to time (the Revenue Obligation Resolution ). The 2006M Bonds now being offered and all obligations heretofore and hereafter issued pursuant to the Revenue Obligation Resolution (collectively, the Revenue Obligations ) are on a parity with each other. The Revenue Obligations are secured by a lien upon and pledge of the Revenue Fund and the revenues of the Authority's System and other moneys paid into the Revenue Fund (the Revenues ) junior, subordinate and inferior to the lien and pledge of Revenues established pursuant to the provisions of a resolution dated August 27, 1990, as amended and supplemented (the Revenue Bond Resolution ), which provides for the issuance of Revenue Bonds (the Revenue Bonds ). See SECURITY FOR THE 2006M BONDS. By supplemental resolution duly adopted, the Authority authorized the issuance of the 2006M Bonds. 1

6 Other Indebtedness of the Authority Pursuant to the Act, the Authority s Board of Directors adopted the Revenue Bond Resolution providing for the issuance of the Authority s Revenue Bonds secured by a lien upon and pledge of Revenues prior and superior to the lien securing the Revenue Obligations. As of July 2, 2006, there was outstanding $227,370,000 aggregate principal amount of Revenue Bonds. Pursuant to the Act and in accordance with the provisions of the Revenue Bond Resolution, the Board of Directors of the Authority adopted the Revenue Obligation Resolution providing for the issuance of the Authority s Revenue Obligations junior to the lien and pledge securing the Revenue Bonds. The Authority has covenanted in the Revenue Obligation Resolution to issue no further Revenue Bonds except for the purpose of refunding Revenue Bonds. As of July 2, 2006 there was outstanding approximately $3,021,857,000 aggregate principal amount of Revenue Obligations. In addition, the Authority has issued indebtedness evidenced by commercial paper notes (the Commercial Paper Notes ) and leases. As of July 2, 2006 there was outstanding $194,994,000 aggregate principal amount of Commercial Paper Notes and approximately $14,607,000 aggregate amount of leases. The lien and pledge of Revenues securing such indebtedness is junior to that securing the Revenue Obligations. See SECURITY FOR THE 2006M BONDS -- Lease Fund Payments and SECURITY FOR THE 2006M BONDS -- Commercial Paper Notes and Revolving Credit Agreement. Purpose of the 2006M Bonds The proceeds of the sale of the 2006M Bonds will be used to fund a portion of the cost of the Authority s ongoing capital improvement program. See CAPITAL IMPROVEMENT PROGRAM. General DESCRIPTION OF THE CURRENT INTEREST BEARING BONDS The Current Interest Bearing Bonds will be dated October 20, 2006 and will mature on January 1, 2013 at the interest rate of 3.75%, on January 1, 2018 at the interest rate of 4.00% and on January 1, 2023 at the interest rate of 4.20%. The Current Interest Bearing Bonds will be issued as registered bonds without coupons in the denominations of five hundred ($500) dollars or any integral multiple thereof. Interest on the Current Interest Bearing Bonds, payable semiannually on each January 1, and July 1 commencing July 1, 2007 (at which time 251 days of interest will be due), will be payable by check or draft mailed by The Bank of New York Trust Company, N.A., as Trustee, to the registered owners thereof as shown on the registration books on the fifteenth day of the month prior to each interest payment date. The maturing principal of the Current Interest Bearing Bonds will be payable at the principal office of the Trustee in the City of New York, New York. The total combined order of the Current Interest Bearing Bonds and Capital Appreciation Bonds, as measured by the initial purchase price thereof, which may be initially purchased by any one investor shall be $10,000. The Current Interest Bearing Bonds may be transferred to another owner but only on the registration books of the Authority held by the Trustee, as registrar. Redemption The Current Interest Bearing Bonds shall be subject to redemption prior to maturity at the option of the Authority on and after January 1, 2007, upon not less than 30 days written notice, as a whole at any time, or in part from time to time on any interest payment date (and, in the event that less than all of the Current Interest Bearing Bonds are called for redemption, the particular Current Interest Bearing Bonds to be redeemed shall be selected by lot by the Trustee, but only in integral multiples of $500 denominations), at the redemption price of 100% of the principal amount of each Current Interest Bearing Bond to be redeemed, together with the interest accrued thereon to the date fixed for redemption. 2

7 Purchase of Current Interest Bearing Bonds by Authority On or after January 1, 2007 any Current Interest Bearing Bond (or portion thereof in authorized denomination) will be purchased by the Authority, on the demand of the registered owner thereof, on the first day (or, if such day is not a business day, on the next succeeding business day) of the first or second month next succeeding the date of delivery of the written notice to the Authority at a purchase price equal to the principal amount thereof less a fee of $15 per $500 principal amount to be purchased, together with accrued interest to the purchase date, upon: (a) delivery to the Authority, of not less than 30 days written notice which states (i) the CUSIP number, face amount, maturity date and series designation of the Current Interest Bearing Bond to be purchased, and (ii) the portion of the principal amount of such Current Interest Bearing Bond to be purchased (provided that such portion shall be an integral multiple of $500), and (b) delivery of such Current Interest Bearing Bond to the Authority, prior to 5:00 p.m. South Carolina time, five business days prior to the date such Current Interest Bearing Bond shall be purchased provided however, that such Current Interest Bearing Bond shall be purchased, only if such Current Interest Bearing Bond delivered to the Authority conforms in all respects to the description in the written notice. The Authority s obligation to redeem 2006M Bonds tendered for purchase is limited to 5% of the original issue amount of the 2006M Bonds in any calendar year. Redemptions will be processed in the order of receipt of redemption requests by the Authority. The Current Interest Bearing Bonds purchased by the Authority at the option of the registered owner are payable from Revenues and other lawfully available funds of the Authority. Failure so to purchase will not constitute a default under the Revenue Obligation Resolution. General DESCRIPTION OF THE CAPITAL APPRECIATION BONDS The Capital Appreciation Bonds will be dated October 20, 2006 and will mature on January 1, 2018 at the interest rate of 4.00% and on January 1, 2023 at the interest rate of 4.20%. The Capital Appreciation Bonds are payable in an amount (the Accreted Value ) equal to the principal amount of such Capital Appreciation Bonds plus interest from the date of such Capital Appreciations Bonds, compounded on January 1 and July 1 of each year. The Capital Appreciation Bonds will be issued as registered bonds without coupons in the denominations of two hundred ($200) dollars or any integral multiple thereof. The Capital Appreciation Bonds will bear interest on the original principal amounts thereof, compounded semiannually on January 1 and July 1 of each year commencing July 1, 2007, and payable only upon maturity or earlier redemption or elective purchase thereof. The maturing Accreted Value of the Capital Appreciation Bonds will be payable at the principal office of the Trustee in the City of New York, New York. The total combined order of Capital Appreciation Bonds and Current Interest Bearing Bonds, as measured by the initial purchase price thereof, which may be initially purchased by any one investor shall be $10,000. The Capital Appreciation Bonds may be transferred to another owner but only on the registration books of the Authority held by the Trustee, as registrar. Redemption The Capital Appreciation Bonds shall be subject to redemption prior to maturity at the option of the Authority on and after January 1, 2007, upon not less than 30 days written notice, as a whole at any time, or in part from time to time on any January 1 or July 1 (and, in the event that less than all of the Capital Appreciation Bonds are called for redemption, the particular Capital Appreciation Bonds to be redeemed shall be selected by lot by the Trustee, but only in integral multiples of $200 denominations), at a redemption price equal to the Accreted Value on the redemption date of any such Capital Appreciation Bond to be redeemed. 3

8 Purchase of Capital Appreciation Bonds by Authority On or after January 1, 2007 any Capital Appreciation Bond (or portion thereof in authorized denomination) will be purchased by the Authority, on the demand of the registered owner thereof, on the first day (or, if such day is not a business day, on the next succeeding business day) of the first or second month next succeeding the date of delivery of the written notice to the Authority at 100% of the Accreted Value thereof on the date of purchase less a fee of $6.00 per $200 original principal amount to be purchased, upon: (a) delivery to the Authority, of not less than 30 days written notice which states (i) the CUSIP number, original principal amount, maturity date and series designation of the Capital Appreciation Bond to be purchased, and (ii) the portion of the original principal amount of such Capital Appreciation Bond to be purchased (provided that such portion shall be an integral multiple of $200), and (b) delivery of such Capital Appreciation Bond to the Authority, prior to 5:00 p.m. South Carolina time, five business days prior to the date such Capital Appreciation Bond shall be purchased; provided, however, such Capital Appreciation Bond shall be purchased only if such Capital Appreciation Bond delivered to the Authority conforms in all respects to the description in the written notice. The Authority s obligation to redeem 2006M Bonds tendered for purchase is limited to 5% of the original issue amount of the 2006M Bonds in any calendar year. Redemptions will be processed in the order of receipt of redemption requests by the Authority. The Capital Appreciation Bonds purchased by the Authority at the option of the registered owner are payable from Revenues and other lawfully available funds of the Authority. Failure so to purchase will not constitute a default under the Revenue Obligation Resolution. 4

9 Accreted Value Table for Capital Appreciation Bonds Maturity January 1, 2018 The Accreted Value amount due at optional redemption, elective purchase or maturity of each $200 original principal amount of any Capital Appreciation Bond with a maturity date of January 1, 2018, as of the first day of each month to maturity will be set forth below. The Accreted Value of each $200 original principal amount of any Capital Appreciation Bond on any other date will be calculated on the assumption that such Accreted Value increases in equal daily amounts on the basis of twelve 30-day months. Date Accreted Value Date Accreted Value Date Accreted Value Jan $ Jul. 1, $ Jan. 1, $ Feb. 1, Aug. 1, Feb. 1, Mar. 1, Sep. 1, Mar. 1, Apr. 1, Oct. 1, Apr. 1, May 1, Nov. 1, May 1, Jun. 1, Dec. 1, Jun. 1, Jul. 1, Jan. 1, Jul. 1, Aug. 1, Feb. 1, Aug. 1, Sep. 1, Mar. 1, Sep. 1, Oct. 1, Apr. 1, Oct. 1, Nov. 1, May 1, Nov. 1, Dec. 1, Jun. 1, Dec. 1, Jan. 1, Jul. 1, Jan. 1, Feb. 1, Aug. 1, Feb. 1, Mar. 1, Sep. 1, Mar. 1, Apr. 1, Oct. 1, Apr. 1, May 1, Nov. 1, May 1, Jun. 1, Dec. 1, Jun. 1, Jul. 1, Jan. 1, Jul. 1, Aug. 1, Feb. 1, Aug. 1, Sep. 1, Mar. 1, Sep. 1, Oct. 1, Apr. 1, Oct. 1, Nov. 1, May 1, Nov. 1, Dec. 1, Jun. 1, Dec. 1, Jan. 1, Jul. 1, Jan. 1, Feb. 1, Aug. 1, Feb. 1, Mar. 1, Sep. 1, Mar. 1, Apr. 1, Oct. 1, Apr. 1, May 1, Nov. 1, May 1, Jun. 1, Dec. 1, Jun. 1, Jul. 1, Jan. 1, Jul. 1, Aug. 1, Feb. 1, Aug. 1, Sep. 1, Mar. 1, Sep. 1, Oct. 1, Apr. 1, Oct. 1, Nov. 1, May 1, Nov. 1, Dec. 1, Jun. 1, Dec. 1, Jan. 1, Jul. 1, Jan. 1, Feb. 1, Aug. 1, Feb. 1, Mar. 1, Sep. 1, Mar. 1, Apr. 1, Oct. 1, Apr. 1, May 1, Nov. 1, May 1, Jun. 1, Dec. 1, Jun. 1,

10 Date Accreted Value Date Accreted Value Date Accreted Value Jul. 1, $ Oct. 1, $ Dec. 1, $ Aug. 1, Nov. 1, Jan. 1, Sep. 1, Accreted Value Table for Capital Appreciation Bonds Maturity January 1, 2023 The Accreted Value amount due at optional redemption, elective purchase or maturity of each $200 original principal amount of any Capital Appreciation Bond with a maturity date of January 1, 2023, as of the first day of each month to maturity will be set forth below. The Accreted Value of each $200 original principal amount of any Capital Appreciation Bond on any other date will be calculated on the assumption that such Accreted Value increases in equal daily amounts on the basis of twelve 30-day months. Date Accreted Value Date Accreted Value Date Accreted Value Jan. 1, $ Jan. 1, $ Jan. 1, $ Feb. 1, Feb. 1, Feb. 1, Mar. 1, Mar. 1, Mar. 1, Apr. 1, Apr. 1, Apr. 1, May 1, May 1, May 1, Jun. 1, Jun 1, Jun. 1, Jul. 1, Jul. 1, Jul. 1, Aug. 1, Aug. 1, Aug. 1, Sep. 1, Sep. 1, Sep. 1, Oct. 1, Oct. 1, Oct. 1, Nov. 1, Nov. 1, Nov. 1, Dec. 1, Dec. 1, Dec. 1, Jan. 1, Jan. 1, Jan. 1, Feb. 1, Feb. 1, Feb. 1, Mar. 1, Mar. 1, Mar. 1, Apr. 1, Apr. 1, Apr. 1, May 1, May 1, May 1, Jun. 1, Jun. 1, Jun. 1, Jul. 1, Jul. 1, Jul. 1, Aug. 1, Aug. 1, Aug. 1, Sep. 1, Sep. 1, Sep. 1, Oct. 1, Oct. 1, Oct. 1, Nov. 1, Nov. 1, Nov. 1, Dec. 1, Dec. 1, Dec. 1, Jan. 1, Jan. 1, Jan. 1, Feb. 1, Feb. 1, Feb. 1, Mar. 1, Mar. 1, Mar. 1, Apr. 1, Apr. 1, Apr. 1, May 1, May 1, May 1, Jun. 1, Jun. 1, Jun. 1, Jul. 1, Jul. 1, Jul. 1, Aug. 1, Aug. 1, Aug. 1, Sep. 1, Sep. 1, Sep. 1, Oct. 1, Oct. 1, Oct. 1, Nov. 1, Nov. 1, Nov. 1, Dec. 1, Dec. 1, Dec. 1,

11 Date Accreted Value Date Accreted Value Date Accreted Value Jan. 1, $ Jun. 1, $ Nov. 1, $ Feb. 1, Jul. 1, Dec. 1, Mar. 1, Aug. 1, Jan. 1, Apr. 1, Sep. 1, Feb. 1, May 1, Oct. 1, Mar. 1, Jun. 1, Nov. 1, Apr. 1, Jul. 1, Dec. 1, May 1, Aug. 1, Jan. 1, Jun. 1, Sep. 1, Feb. 1, Jul. 1, Oct. 1, Mar. 1, Aug. 1, Nov. 1, Apr. 1, Sep. 1, Dec. 1, May 1, Oct. 1, Jan. 1, Jun. 1, Nov. 1, Feb. 1, Jul. 1, Dec. 1, Mar. 1, Aug. 1, Jan. 1, Apr. 1, Sep. 1, Feb. 1, May 1, Oct. 1, Mar. 1, Jun. 1, Nov. 1, Apr. 1, Jul. 1, Dec. 1, May 1, Aug. 1, Jan. 1, Jun. 1, Sep. 1, Feb. 1, Jul. 1, Oct. 1, Mar. 1, Aug. 1, Nov. 1, Apr. 1, Sep. 1, Dec. 1, May 1, Oct. 1, Jan. 1, Jun. 1, Nov. 1, Feb. 1, Jul. 1, Dec. 1, Mar. 1, Aug. 1, Jan. 1, Apr. 1, Sep. 1, May 1, Oct. 1,

12 DEBT SERVICE SCHEDULE(1) (Thousands of Dollars) The following table sets forth on an accrual basis the debt service due on outstanding Revenue Bonds, outstanding Revenue Obligations, the 2006M Bonds and the total debt service due on all outstanding bonds of the Authority in each calendar year indicated. Calendar Year Outstanding Revenue Bonds Outstanding Revenue Obligations (2) 2006M Bonds Total Debt Service 2006 $12,140 $224,635 $ - $236,775(3) , , , , , , , , , , , , , , , , ,834 2, , , , , , , , , , , , , , , ,662 5, , , , , , , , , , , , , , , ,671 4, , ,028 99, , ,146 90,833 95, ,096 84,598 88, ,156 78,628 88, ,216 76,022 92, ,217 76,053 92, ,215 76,288 92, ,216 76,066 92, ,105 74,031 82, ,466 62, ,444 62, ,399 62, ,098 62, ,718 62, ,674 21, ,428 20,428 (1) Does not include payments into the Lease Fund or debt service on Commercial Paper Notes which are junior to debt service on Revenue Obligations. Does not reflect puts subsequent to June 15, 2006 of Revenue Obligations subject to tender for elective purchase. Does not reflect funds available from reserves upon maturity of individual issues. (2) Includes debt service on the Revenue Obligations, 2006 Refunding Series C, which are scheduled to close on November 16, (3) Excludes six months debt service totaling $2,301,610 on the Original Bonds which matured on July 1, 2006 and are no longer outstanding. 8

13 SECURITY FOR THE 2006M BONDS General In the Revenue Obligation Resolution, the Authority has covenanted not to issue any additional Revenue Bonds except for purposes of refunding outstanding Revenue Bonds. See Appendix II -- SUMMARY OF CERTAIN PROVISIONS OF THE REVENUE OBLIGATION RESOLUTION. The 2006M Bonds are payable solely from, and secured by a lien upon and pledge of, the Revenues on a parity with the lien and pledge securing Revenue Obligations heretofore and hereafter issued pursuant to the Revenue Obligation Resolution, but junior and subordinate to the lien upon and pledge of Revenues to be paid into the Revenue Bond Fund and the accounts therein, established for the payment of the Revenue Bonds pursuant to the provisions of the Revenue Bond Resolution; but, nevertheless, senior to (i) payments required to be made from or retained in the Revenue Fund to pay expenses of operating and maintaining the System, and (ii) the payments into the Lease Fund and the Capital Improvement Fund heretofore established and continued under the Revenue Obligation Resolution. See FINANCIAL INFORMATION. The Revenue Bonds and the Revenue Obligations, including the 2006M Bonds, are not obligations of the State, nor of any political subdivision thereof, and neither the State nor any of its political subdivisions shall be liable thereon, nor shall they be payable from any funds other than the Revenues of the Authority and moneys in the Revenue Fund pledged to the payment thereof. Additional series of Revenue Obligations may be issued without limitation and without compliance with any additional bonds test, provided there is no default under the Revenue Bond Resolution or Revenue Obligation Resolution. In addition, no debt service reserve fund is established under the Revenue Obligation Resolution. See Appendix II -- SUMMARY OF CERTAIN PROVISIONS OF THE REVENUE OBLIGATION RESOLUTION. Rate Covenant The Revenue Obligation Resolution provides that the Authority shall establish, maintain and collect rents, tolls, rates and other charges for power and energy and all other services, facilities and commodities sold, furnished or supplied through the facilities of the System which shall be adequate to provide the Authority with Revenues sufficient: (a) to pay the principal of, premium, if any, and interest on the Revenue Bonds and the Revenue Obligations as and when the same shall become due and payable; (b) to make when due all payments which the Authority is obligated to make (i) into the Revenue Bond Fund, (ii) into the Revenue Obligation Fund created under the Revenue Obligation Resolution, (iii) into the Lease Fund, and (iv) into the Capital Improvement Fund pursuant to the Revenue Bond Resolution and the Revenue Obligation Resolution; (c) to make all other payments which the Authority is obligated to make pursuant to the Revenue Bond Resolution and the Revenue Obligation Resolution; (d) to pay all proper operation and maintenance expenses and all necessary repairs, replacements and renewals thereof; (e) to pay all taxes, assessments or other governmental charges lawfully imposed on the Authority or the Revenues thereof or payments in lieu thereof; and (f) to pay any and all amounts which the Authority may become obligated to pay from the Revenues of the System by law or by contract. As required by the Act, the Authority makes distributions to the State and payments in lieu of taxes to local governments. Nothing in the Act prohibits the Authority from paying to the State each year up to 1% of its projected operating revenues, as such revenues would be determined on an accrual basis, from the combined electric and water systems. In 2005, such distributions and payments amounted to approximately $19,310,000. There is no agency, other than the Authority, having jurisdiction over the rates, except for wholesale transmission rates, of the Authority. See COMPETITION. 9

14 Additional Indebtedness The Revenue Obligation Resolution does not prohibit the issuance of obligations secured by a pledge of the Revenues junior and subordinate to the pledge securing the Revenue Obligations. In addition, the Authority may issue obligations secured by a pledge of revenues derived from separate utility systems not included in the System. See Appendix II -- SUMMARY OF CERTAIN PROVISIONS OF THE REVENUE OBLIGATION RESOLUTION -- Separate Systems. Lease Fund Payments As of July 2, 2006 the aggregate principal payments required to be made into the Lease Fund through the year 2014 was approximately $14,607,000 under existing leases of properties and facilities leased to the Authority. The required payments into the Lease Fund are secured by a lien upon and pledge of Revenues junior to the lien and pledge securing Revenue Obligations. Commercial Paper Notes and Revolving Credit Agreement The Board of Directors of the Authority has by resolution authorized the issuance of not exceeding $500,000,000 aggregate principal amount at any one time outstanding of Commercial Paper Notes which are secured by a lien upon and pledge of Revenues junior to the lien and pledge securing (i) Revenue Bonds, (ii) Revenue Obligations, (iii) expenses of operating and maintaining the System, and (iv) payments into the Lease Fund, but prior to the payments into the Capital Improvement Fund. As of July 2, 2006, there was outstanding $194,994,000 aggregate principal amount of Commercial Paper Notes. To obtain funds, if needed to repay the Commercial Paper Notes, the Authority has entered into a Revolving Credit Agreement (the Revolving Credit Agreement ), with Dexia Crédit Local, acting through its New York Agency, and BNP Paribas, acting through its San Francisco Branch (collectively, the Banks ), and Dexia Crédit Local as Agent for the Banks, pursuant to which the Authority may borrow up to $450,000,000. The Authority s obligation to repay any such loan is secured by a lien upon and pledge of Revenues pari passu with the lien upon and pledge of Revenues securing the Commercial Paper Notes. There has been no borrowing by the Authority under the Revolving Credit Agreement. Capital Improvement Fund Requirement The Revenue Obligation Resolution requires, so long as any Revenue Obligations are outstanding, that the Authority deposit annually into the Capital Improvement Fund an amount which, together with the amounts deposited therein in the two immediately preceding Fiscal Years, will be at least equal to 8% of the Revenues required by the Revenue Obligation Resolution to be paid into the Revenue Fund in the three immediately preceding Fiscal Years. When no Revenue Bonds are outstanding, permitted use of moneys in the Capital Improvement Fund is broadened to include payment of Capital Costs, as defined in the Revenue Obligation Resolution. See Appendix II -- SUMMARY OF CERTAIN PROVISIONS OF THE REVENUE OBLIGATION RESOLUTION. 10

15 ORGANIZATION AND MANAGEMENT OF THE AUTHORITY Pursuant to the Act, the Authority s Board of Directors, appointed by the Governor, shall consist of eleven members, who reside in South Carolina and who shall have the qualifications provided for in the Act as determined by the State Regulation of Public Utilities Review Committee, and confirmed by the State Senate, as follows: one from each congressional district of the State; one from each of the counties of Berkeley, Horry and Georgetown who reside in the territory of the Authority and are customers of the Authority and two from the State at large, one of whom shall be chairman. Two of the directors shall have substantial work experience within the operations of electric cooperatives or substantial experience on an electric cooperative board, but must not serve as an employee or board member of an electric cooperative during their term as director. Each director shall serve for a term of seven years and until his successor has been appointed and qualified. Directors appointed to fill a vacancy on the board shall serve for the unexpired portion of the term only and until a successor has been appointed and qualified. Directors may be removed from office only for cause. An individual appointed as a director may not serve on the board, even in an interim capacity, until he has been screened and found qualified by the State Regulation of Public Utilities Review Committee. The Act prescribes the manner in which a director shall discharge his duties and sets forth conditions by which a director may be held accountable for his actions or inactions as a director. Present directors are listed below. Term Expires Name Business Residence May O. L. Thompson, Chairman Business Executive Charleston 2011 G. Dial Dubose, First Vice Chairman Business Executive Easley 2005(1) Clarence Davis, Second Vice Chairman Attorney Columbia 2008 J. Calhoun Land, IV Attorney Manning 2006(1) Paul G. Campbell, Jr. Retired Business Executive Goose Creek 2007 Barry D. Wynn Business Executive Spartanburg 2007 David A. Springs Retired Business Executive Murrells Inlet 2008 John T. Molnar Medical Doctor Myrtle Beach 2009 James W. Sanders, Sr. Pastor Gaffney 2009 Cecil E. Viverette Retired Business Executive Hilton Head 2012 William A. Finn Business Executive Charleston 2013 (1) Although their terms expired as indicated, they may continue to serve until successors have been appointed and qualified. 11

16 The President and Chief Executive Officer of the Authority is appointed by the Authority s Board of Directors. The Authority's executive management is appointed by the President and Chief Executive Officer with the approval of the Authority s Board of Directors. Authority executive management is: Utility Name Position Experience Lonnie N. Carter President and Chief Executive Officer 24 years Bill McCall, Jr. Executive Vice President and Chief Operating Officer 35 years Elaine G. Peterson Executive Vice President and Chief Financial Officer 29 years James E. Brogdon, Jr. Senior Vice President and General Counsel 1 year Rennie M. Singletary, III Senior Vice President, Corporate Services 29 years Lonnie N. Carter joined the Authority in 1982 as an employee in the Controller s Office. Since that time he has held various positions, including Manager of Corporate Forecasting, Vice President of Corporate Forecasting, Senior Vice President of Customer Service and Senior Vice President of Corporate Planning & Bulk Power. In 1997, he served as the first President and Chief Executive Officer of The Energy Authority, Inc. ( TEA ), a joint power marketing alliance through a non-profit corporation, whereby the Authority can purchase or sell energy and/or capacity when available. In 2004 he became President and Chief Executive Officer. He received a Bachelor of Science degree in Business Administration and a Masters in Business Administration from The Citadel. Bill McCall, Jr. joined the Authority in 1971 as an engineer. Since that time he has held various positions, including Group Manager Production Operations, Manager Station Construction, Vice President Production Operations, Vice President Horry-Georgetown Division, Executive Vice President Generation and Chief Operating Officer. He received a Bachelor of Science degree in Mechanical Engineering from the University of South Carolina and a Masters in Business Administration from The Citadel. Elaine G. Peterson joined the Authority in 1977 as an accountant in the Authority s Career Foundation Program. Since that time she has held various positions, including Assistant to the Controller, Program for Employee Participation Coordinator, and Controller. She received a Bachelor of Science degree in Accounting from Clemson University and a Masters in Business Administration from The Citadel. James E. Brogdon, Jr. joined the Authority in 2005 as Senior Vice President and General Counsel and a member of the executive management team. He practiced law in private practice and served as a judge of the South Carolina Circuit Court from 1996 to February He received a Bachelor of Arts degree in Economics from Wofford College and a Juris Doctor from the University of South Carolina School of Law. Rennie M. Singletary joined the Authority in 1977 as an engineer. Since that time he has held various positions, including Jefferies Generating Station Manager and Vice President of Fossil and Hydro Generation. He received a Bachelor of Science degree and a Master of Science degree in Mechanical Engineering from Clemson University and a Masters in Business Administration from The Citadel. The Authority had 1,737 employees as of July 1, Authority employees are members of a contributory state pension plan administered by the South Carolina State Retirement System. The Act establishes an Advisory Board composed of the following officials of the State: the Governor, the Attorney General, the State Treasurer, the Comptroller General and the Secretary of State. The Advisory Board approves the hiring of the external auditors and sets the salary of the Authority s Board of Directors. 12

17 CUSTOMER BASE Service Area The Authority, among other things, produces, transmits and distributes electrical energy, both at wholesale and retail, to citizens of South Carolina. The Authority is one of the nation's largest municipal wholesale utilities, whose System serves directly or indirectly over one-third of the State s population. The Authority serves directly and indirectly some of the most rapidly developing areas of the State, including growing suburban areas outside Charleston, Columbia, Greenville and Spartanburg as well as the coastal areas of Myrtle Beach and the Grand Strand, Hilton Head Island, Kiawah Island and Seabrook Island. The Authority's direct customers currently include 32 large industrial customers, Central Electric Power Cooperative Inc. ( Central ), and two municipal electric systems, the City of Georgetown and the City of Bamberg. Central is an association of 15 electric distribution cooperatives and Saluda River Electric Cooperative, Inc. ( Saluda ). Saluda is an association of five electric distribution cooperatives. Central serves primarily residential, commercial and small industrial customers in all 46 counties of the State. Through Central, Saluda and the two municipal electric systems, approximately 675,000 customers are served indirectly by the Authority. See CUSTOMER BASE -- Wholesale. The Authority also serves directly approximately 154,000 residential, commercial and small industrial retail customers in parts of Berkeley, Georgetown and Horry counties. See CUSTOMER BASE -- Direct Retail Service Area. The Authority, from time to time, negotiates with existing and prospective customers and entities for the sale of electric power under long-term contracts. The Authority is unable to predict the outcome of such negotiations. Wholesale Central. Central is a generation and transmission cooperative that provides wholesale electric service to Saluda and each of the 15 distribution cooperatives (the Central Cooperatives ) which are members of Central pursuant to long-term all requirements power supply agreements. See CUSTOMER BASE -- Wholesale -- Saluda. The Central Cooperatives serve areas ranging from sparsely populated rural areas to heavily populated suburban areas. The table below lists each of the Central Cooperatives, the location of their headquarters, and the number of customers of each as of December 31, 2005, which is the latest information provided by Central. Central Cooperatives Headquarters Customers Aiken Electric Cooperative, Inc. Aiken 42,380 Berkeley Electric Cooperative, Inc. Moncks Corner 72,687 Black River Electric Cooperative, Inc. Sumter 29,106 Coastal Electric Cooperative, Inc. Walterboro 11,134 Edisto Electric Cooperative, Inc. Bamberg 19,211 Fairfield Electric Cooperative, Inc. Winnsboro 22,467 Horry Electric Cooperative, Inc. Conway 55,193 Lynches River Electric Cooperative, Inc. Pageland 20,141 Marlboro Electric Cooperative, Inc. Bennettsville 6,484 Mid-Carolina Electric Cooperative, Inc. Lexington 46,346 Newberry Electric Cooperative, Inc. Newberry 11,999 Palmetto Electric Cooperative, Inc. Ridgeland 61,822 Pee Dee Electric Cooperative, Inc. Darlington 29,658 Santee Electric Cooperative, Inc. Kingstree 43,125 Tri-County Electric Cooperative, Inc. St. Matthews 17,646 13

18 The Authority supplies the total power and energy requirements of the Central Cooperatives and Saluda, less amounts which Central and Saluda purchase directly from Southeastern Power Administration ( SEPA ), small amounts purchased from others and amounts provided by Saluda s ownership interest in the Catawba Nuclear Station and a small run of the river hydroelectric plant. The amounts supplied by the Authority are determined under the terms of an agreement between the Authority and Central (the Central Agreement ) which became effective January 1981 upon approval by the Rural Electrification Administration, currently the Rural Utilities Services ( RUS ). In 2005, revenues pursuant to the Central Agreement amounted to approximately 50.6% of revenues from sales. The Authority and Central adopted an amendment to the Central Agreement in January 1988 which was approved by the RUS on July 20, 1988 and which revised the cost of service methodology, lowered the cost responsibility and rates to Central and extended the contract for a 35 year period ending on March 31, In addition to the change in the costing methodology, the amendment relinquishes all ownership rights of future generation by Central. Under State law, the Authority may only serve directly new industrial customers located in its direct service area. However, if any industrial customers located outside the Authority's service area discontinue accepting electrical service from the Authority, the Authority may sell electrical service to new customers from its major transmission lines in areas outside the Authority s service area in an amount not exceeding that which was lost by such discontinuation of service. If a new customer is served by a Central Cooperative, the Authority will provide such power to the customer through the Central Cooperative. Central and the Authority have joined together to form a joint economic development effort, known as the Palmetto Economic Development Corporation, to benefit the State, the Authority and Central. Formed in September 1988, it works to more effectively recruit new industries and to increase job opportunities throughout the State. The joint operation is governed by an eight-member board of directors, four named by Central and four named by the Authority. Saluda. Saluda is a generation cooperative that provides wholesale electric service to each of the five electric cooperatives (the Saluda Cooperatives ) that are members of Saluda. The Saluda Cooperatives serve areas ranging from sparsely populated rural areas to heavily populated suburban areas located in the Western portions of the State. Saluda became a member of Central in May Subject to the terms of a wholesale power contract between Central and Saluda, the Authority provides Saluda s power requirements, above the load provided by Catawba Nuclear Station and SEPA resources, under the Central Agreement. Under agreements between Central and the Saluda Cooperatives, each of the Saluda Cooperatives becomes a member of Central at the earlier of (i) such time as Saluda ceases its corporate existence or (ii) January 31, At such time, the Saluda Cooperatives become all requirements customers of Central and receive their power requirements from the Authority under the Central Agreement. The table below lists each of the Saluda Cooperatives, the location of their headquarters, and the number of customers of each as of December 31, 2005, which is the latest information provided by Saluda. Saluda Cooperatives Headquarters Customers Blue Ridge Electric Cooperative, Inc. Pickens 60,583 Broad River Electric Cooperative, Inc. Gaffney 19,697 Laurens Electric Cooperative, Inc. Laurens 48,573 Little River Electric Cooperative, Inc. Abbeville 13,504 York Electric Cooperative, Inc. York 35,910 For additional information on Central, the Central Cooperatives, Saluda and the Saluda Cooperatives, please refer to the 2004 Statistical Report, Rural Electric Borrowers (RUS Informational Publication 201-1) which is the latest available statistical report, copies of which may be obtained from the U.S. Government Printing Office, Superintendent of Documents, Mail Stop: SSOP, Washington, D.C

19 Other Wholesale. In addition to Central, the Authority provides wholesale electric service to the City of Georgetown, the City of Bamberg, and South Carolina Electric & Gas ( SCE&G ) pursuant to long-term contracts. Sales to these customers and off-system sales to other utilities and power marketers during 2005 represented approximately 2.2% of revenues from sales. Direct Retail Service Area The Authority owns distribution facilities and serves in two non-contiguous areas covering portions of Berkeley, Georgetown and Horry Counties. These service areas include 2,440 miles of distribution lines. The following table presents retail customer growth from 2001 through 2005 in these areas. Retail Customers Commercial Year Residential and Small Industrial Total Annual Increase % ,740 24, , ,267 25, , ,213 25, , ,667 26, , ,440 27, , Sales to residential, commercial, small industrial customers and certain other customers are made pursuant to rate schedules established from time to time by the Authority. All such rate schedules include a fuel adjustment clause and demand sales adjustment clause. Sales to this customer group represented approximately 20.1% of revenues from sales in Large Industrial Contracts Sales to large industrial customers are made pursuant to long-term contracts. The Authority offers a large power rate schedule prepared on a cost of service basis for large industrial customers which contract for a minimum of 1,000 kilowatts ( kw ). The Authority requires that such customers enter into contracts for initial periods of not less than five years. All contracts contain rate provisions of the demand and energy type, and include fuel adjustment clauses, demand sales adjustment clauses and other provisions generally used in large industrial power rate schedules. The average cost per kilowatthour ( kwh ) varies depending upon the customer's usage and load factor. Sales to large industrial customers during 2005 represented approximately 27.0% of revenues from sales, which includes 10.7% for Alumax of South Carolina, Inc. ( Alumax ), 6.4% for Nucor Corporation ( Nucor ), and 6.8% for the next eight largest industrial customers, of which no one customer represents more than 1.7% of sales. Long-Term Power Contract With Alumax. The Authority has a long-term power contract with Alumax which extends through December 31, The contract provides for the delivery of approximately 400 Megawatts ( MW ) of power under three different rate schedules or riders. Approximately 40% of the load is served under the Authority s firm industrial rate schedule, with the majority of the remainder served under the supplemental curtailable schedule which provides that either party may curtail power served under the schedule with six months notice. A small portion of the load is served under the interruptible rate schedule. Alumax s obligations under the contract are guaranteed by its parent company, Alcoa, Inc. Long-Term Power Contract with Nucor. The Authority has a long-term power contract with Nucor which extends through April 30, 2009 and provides for two year rollover terms thereafter. The contract currently provides for delivery of approximately 300 MW of power, none of which is provided under the supplemental curtailable rate schedule. 15

20 POWER SUPPLY AND POWER MARKETING Generating Facilities The Authority's generating facilities consist of the following facilities: Initial Date in Service Winter Peak Capability (MW) Summer Peak Capability (MW) Energy Source Generating Facilities Location Jefferies Hydroelectric Generating Station... Moncks Corner Hydro Wilson Dam Generating Station... Lake Marion Hydro Jefferies Generating Station... Moncks Corner Nos. 1 and Oil Nos. 3 and Coal Grainger Generating Station Nos. 1 and 2 Conway Coal Combustion Turbines Nos. 1 and 2... Myrtle Beach Oil/Gas Combustion Turbines Nos. 3 and 4... Myrtle Beach Oil Combustion Turbine No Myrtle Beach Oil Combustion Turbine No Hilton Head Island Oil Combustion Turbine No Hilton Head Island Oil Combustion Turbine No Hilton Head Island Oil Winyah Generating Station... Georgetown No Coal No Coal No Coal No Coal Summer Nuclear Station(1)... Jenkinsville (2) 318(2) Nuclear Cross Generating Station... Cross Unit Coal Unit Coal Horry Landfill Gas Station... Conway LMG(3) Lee County Landfill Gas Station... Bishopville LMG Richland County Landfill Gas Station.. Elgin LMG Rainey Generating Station... Starr Unit Gas Unit 2A Gas Unit 2B Gas Unit Gas Unit Gas Unit Gas Diesel Generating Units (4) Oil Total Capability 4,687 4,509 (1) Virgil C. Summer Nuclear Station ( Summer Nuclear Station ). (2) Represents the Authority's one-third ownership interest. (3) Landfill Methane Gas ( LMG ) (4) Year Purchased by the Authority. 16

21 Power Resources The Authority plans for firm power supply from its own generating capacity and firm power contracts to equal its firm load, including a 13% summer reserve margin. The Authority s current total summer peak generating capability is 4,509 MW, of which 2,791 MW is generated by coal-fueled units, 130 MW by hydroelectric stations, 318 MW by a nuclear-fueled unit, 1,257 MW by oil, gas or oil/gas-fueled units and 13 MW from landfill methane gas. In addition, the Authority presently receives 84 MW of firm supply from the U.S. Army Corps of Engineers (the Corps ) and 327 MW of firm hydroelectric power from SEPA. The SEPA allocation consists of 192 MW for wheeling to the SEPA preference customers served by the Authority and 135 MW purchased by the Authority for its customers. For the summer of 2006, the Authority purchased 165 MW of firm power from Duke Energy and 275 MW of firm power from Progress Ventures, Inc. ( PV ). The 851 MW supplied under contract by PV, SEPA and the Corps, combined with the Authority s generating capability of 4,509 MW, brought the Authority s total 2006 summer power supply peak capability to 5,360 MW. The Authority has also entered into a power purchase agreement with the county of Greenwood, South Carolina for as-available capacity and energy from the Buzzard Roost hydro electric generating facility. Further, the Authority s Board of Directors authorized management to enter into a lease of the Buzzard Roost facility. The power purchase agreement will be in effect until the end of 2006 or the effective date of the lease. The electric generation, transmission and distribution facilities owned by the Authority as well as certain generation and transmission facilities leased from Central, are operated by the Authority as a fully integrated electric system. The Authority has direct interconnections with five entities, including all those with which the Authority has long-term power contracts for energy interchange. See POWER SUPPLY AND POWER MARKETING -- Power Resources and POWER SUPPLY AND POWER MARKETING -- Interconnections and Interchanges. The table below details the Authority's resources classified by energy source for the 2006 summer power supply peak capability. Source of Power Supply (MW) % of Total Coal... 2, Natural Gas and Oil... 1, Nuclear Owned Hydro Generation Landfill Methane Gas Total Generating Capability... 4,509 SEPA, Corps, Duke Energy & PV Total Generating Capability and Purchases 5, Non-nuclear Generating Availability. The following table sets forth performance indicators for the Authority s coal-fired generation for the years 2003 through Capacity Factor -% Availability Factor - % Forced Outage Rate -% Net Heat Rate (BTU/Kwh)... 10,031 9,998 9,969 Performance monitoring systems are in place at the Authority s coal-fired generating stations and at its Rainey Generating Station to optimize each unit s operation while complying with environmental requirements. 17

22 All units are maintained with computerized maintenance management systems and the use of preventive, predictive, and proactive maintenance practices to achieve high reliability and efficiency at low maintenance cost. In its maintenance program, the Authority utilizes technologies such as vibration analysis, oil analysis, thermography, laser alignment, and non-destructive testing. The Authority continues to implement equipment maintenance programs for the units including major unit components such as control systems, steam generators, and turbine generators. See CAPITAL IMPROVEMENT PROGRAM. Summer Nuclear Station. The Authority owns a one-third undivided interest in the Summer Nuclear Station located in Fairfield County, South Carolina. The station has a pressurized water reactor with a maximum dependable rating of 954 MW net. SCE&G owns the remaining two-thirds interest and operates and maintains the station on its own behalf and as the Authority's agent. The following table sets forth certain performance indicators for the Summer Nuclear Station for the years 2003 through 2005 and for the period of commercial operation, January 1, 1984 through December 31, The 2003 refueling outage began October 11, 2003 and was completed on November 26, The 2005 refueling outage began on April 23, 2005 and was completed on June 1, The 2006 refueling outage is scheduled to commence on October 13, 2006 and last for 35 days. January 1, December 31, 2005 Net Generation -- Mwh 7,352,094 8,243,336 7,469, ,715,529 Capacity Factor -- % Availability Factor -- % Forced Outage Rate -- % The Nuclear Regulatory Commission (the NRC ) oversees plant performance through the Plant Performance Review (the PPR ). The PPR is an ongoing process that combines the evaluation of inspection results and safety performance information. PPR results are classified into the areas of Reactor Safety, Radiation Safety and Safeguards and are used to identify and evaluate trends. Results are classified as green, yellow, white or red, with green being most favorable. A green classification indicates that plant management has proper oversight and does not require additional regulator oversight. Through the second quarter of 2006, all PPR classifications for Summer Nuclear Station are coded green, except the Public Radiation Cornerstone is coded white. The station violated a Department of Transportation rule during a low level radioactive waste shipment. At no time during the shipment was the health or safety of the public in danger. The station is in the Regulatory Response Column of the NRC Action Matrix. In 2004, the NRC extended the operating license for Summer Nuclear Station to August 6, 2042, which was an additional twenty years. Transmission The Authority operates an integrated transmission system which includes lines owned and leased by the Authority as well as those owned by Central. The transmission system includes approximately 1,008 miles of 230 kilovolt ( kv ), 1,632 miles of 115 kv, 1,689 miles of 69 kv, 18 miles of 46 kv and 96 miles of 34 kv overhead and underground transmission lines. The Authority operates 83 transmission substations and switching stations serving 77 distribution substations and 343 Central Cooperative delivery points. Communications sites at 97 locations are in place to support the monitoring and controlling of integrated power system operations. The Authority plans the transmission system to operate during normal and single contingency conditions and to maintain system voltages that are consistent with good utility practice. Interconnections and Interchanges The Authority's transmission system is interconnected with other major electric utilities in the region. It is directly interconnected with SCE&G at eight locations; with Progress Energy Carolinas ( Progress Energy ) at five locations; with Southern Company Services, Inc. ( Southern Company ) at one location; and with Duke Energy Carolinas, a subsidiary of Duke Energy Corporation ( Duke ), at two locations. The Authority is also interconnected with SCE&G, Duke, Southern Company and SEPA through a five-way 18

23 interconnection at SEPA's J. Strom Thurmond Hydroelectric Project, and with Southern Company and SEPA through a three-way interconnection at SEPA's R. B. Russell Hydroelectric Project. Through these interconnections, the Authority's transmission system is integrated into the regional transmission system serving the southeastern areas of the United States and the Eastern Interconnection. The Authority has separate interchange agreements with each of the companies with which it is interconnected which provide for mutual exchanges of power. The Authority is currently developing two additional ties with Progress Energy. Reliability Agreements The Authority is a party to the Virginia-Carolinas Reliability Agreement ( VACAR ) which exists for the purpose of safeguarding the reliability of electric service of the parties thereto. Other parties to the VACAR agreement are SCE&G, Progress Energy, Duke, SEPA, APGI-Yadkin Division, Dominion Virginia Power, North Carolina Electric Membership Corporation, North Carolina Eastern Municipal Power Agency, North Carolina Municipal Power Agency Number 1 and Public Works Commission of the City of Fayetteville. As a party to VACAR, the Authority is also a member of the Southeastern Reliability Corporation, which is one of 8 regions of the North American Electric Reliability Council. Distribution The Authority owns distribution facilities in two service areas: the Berkeley District serving retail customers in St. Stephen, Bonneau Beach, Moncks Corner and Pinopolis; and the Horry-Georgetown Division serving retail customers in Conway, Myrtle Beach, North Myrtle Beach, Loris, Briarcliffe, Surfside Beach, Atlantic Beach, Pawleys Island, unincorporated areas along the Grand Strand and portions of rural Georgetown and Horry Counties. See CUSTOMER BASE. General Plant The Authority owns general plant consisting of office facilities; transportation and heavy equipment; computer equipment; and communication equipment necessary to support the Authority's operations. The Authority has eight customer service offices throughout its direct service territory and corporate headquarters located in Moncks Corner which includes a garage, maintenance facilities and warehouse facilities. Fuel Supply During 2005, the Authority's energy supply, including energy wheeled to SEPA preference customers, was derived approximately 72.4% from coal-fueled generation, 8.1% from natural gas and oil generation, 9.5% from nuclear-fueled generation, 1.8% from the Authority's hydro generation, 8.1% from purchases from other electric utilities and marketing agencies and 0.1% from landfill methane gas. Coal. The Authority has contracted for bituminous coal for its Grainger, Jefferies, Winyah and Cross Generating Stations from a number of companies, and additional coal is acquired from spot market purchases. All of the Authority's suppliers have loading facilities for providing delivery of coal in unit train shipments. The Authority owns 774 coal cars and leases additional coal cars as needed. As of September 30, 2006, the Authority had sufficient coal, including bed coal, on hand to satisfy its requirements for approximately 58 days of projected operation. The Authority s target for coal on hand is approximately 50 days of projected operation. Sulfur dioxide ( SO 2 ) air emission limitations dictate the maximum amount of coal sulfur content that can be used by generating units. Such requirements range from a limit of 1.2% sulfur in the case of Unit 2 at the Winyah Generating Station to a maximum of 2.5% in the case of Unit 1 at the Cross Generating Station. The sulfur content of coal received under existing contracts ranges from approximately 0.9% to 2.5%. The Authority believes it can obtain an adequate coal supply with sulfur content within acceptable ranges to meet foreseeable needs. See REGULATORY MATTERS -- Environmental Matters. 19

24 Gas. The Authority has contracted with Transcontinental Gas Pipeline Corporation ( Transco ) to provide firm gas transportation in an amount approximately equal to the Rainey Generating Station combined cycle unit at full load. Any additional gas transportation necessary to fuel the remaining needs of the simple cycle units at the station will be purchased on a non-firm basis. If gas is unavailable or uneconomical, the Authority will operate the station using fuel oil where possible. The Authority has backup oil storage facilities on site. The Authority s Board of Directors has approved a policy that deals with the philosophy, framework and delegation of authorities necessary to govern the activities related to the Authority s natural gas risk management program. TEA. The Authority has determined that all transactions executed under the policy will be executed through Nuclear. Under the Joint Ownership Agreement for Summer Nuclear Station, Unit 1 (the Summer Nuclear Agreement ), SCE&G acts for itself and as agent for the Authority in the operation of the Summer Nuclear Station including the acquisition and management of nuclear fuel. Fuel supply needs until 2008 will be met by acquiring enriched product from the United States Enrichment Corporation. Current plans are to continue using the United States Enrichment Corporation to obtain enrichment services and fuel for the 2009 refueling outage. A contract to obtain fuel beyond 2009 is expected to be negotiated during Summer Nuclear Station has licensed on-site spent fuel storage capability until 2018 while still maintaining full core discharge capability. The station expects to be able to expand its storage capability over the plant life to accommodate the spent fuel through spent fuel rod reracking, dry cask storage or other technology as it becomes available. Under the provisions of the Nuclear Waste Policy Act of 1982, on June 29, 1983 SCE&G and the Authority entered into a contract (the Standard Contract ) with the Department of Energy (the DOE ) for spent fuel and high level waste disposal services for the operating life of the Summer Nuclear Station. The Nuclear Waste Policy Act and the Standard Contract require the DOE to accept and dispose of spent nuclear fuel and high-level radioactive waste beginning not later than January 31, To date, the DOE has accepted no spent fuel from Summer Nuclear Station or any other utility, and has indicated that it does not anticipate doing so until On January 28, 2004, SCE&G and the Authority, in their capacity as co-owners of the Summer Nuclear Station, filed a breach of contract claim against the DOE in the U.S. Court of Claims. This is one of 66 similar lawsuits brought by nuclear facility owners as of January 29, On January 9, 2006, SCE&G, the Authority and the United States Department of Justice entered into a formal written settlement agreement that resolved all issues in the litigation pending in the U.S. Court of Claims and resulted in the dismissal of that litigation with prejudice. Among other things, the agreement provides for the payment of $9,000,000 to SCE&G and the Authority for costs they would not have had to incur but for the delay by the DOE in performing its obligations under the Standard Contract. On a prospective basis, the agreement provides a mechanism for SCE&G and the Authority to recover additional costs associated with any further delay by the DOE in performing its obligations under the Standard Contract. 20

25 Fuel Costs The Authority s rates include various fuel adjustment provisions. Base fuel charges are adjusted to reflect actual fuel costs on a monthly basis for Central and on a three month moving average for most other customers. Coal, natural gas and oil prices have risen dramatically over the past two years. The Authority strives to mitigate these costs with a combination of long-term and short-term contracts, a gas risk hedging program and burning a variety of solid fuels (petcoke, coal, and synfuel). Synfuel production, however, is tied to crude oil prices and has been curtailed by some producers and could be phased out completely before the 2007 ending date mandated by federal law. The Energy Authority The Authority is a member of TEA along with the City Utilities of Springfield (Missouri), Gainesville Regional Utilities (Florida), JEA, MEAG Power, and Nebraska Public Power District. TEA markets wholesale power and coordinates the operation of the generation assets of its members to maximize the efficient use of electrical energy resources, reduce operating costs and increase operating revenues of the members. TEA is expected to accomplish the foregoing without impacting the safety and reliability of the electric system of each member. In addition, TEA purchases and sells natural gas relating to fuel for members generation of electricity. TEA does not engage in the construction or ownership of generation or transmission assets. As described below under COMPETITION -- Changes in Federal Regulation of Electric Utilities, the standard of conduct provisions of Order 2004 of the Federal Energy Regulatory Commission (the FERC ) require that employees of a utility engaged in transmission system operations function independently of employees of the utility or any of its affiliates who are engaged in the wholesale merchant function. The Authority believes that the establishment of TEA assists in satisfying that requirement. All of TEA s revenues and its costs are allocated to the members. The Authority's exposure relating to TEA is limited to the Authority s capital investments in TEA, any accounts receivable from TEA and trade guarantees provided to TEA by the Authority. The current amount approved by the Authority s Board of Directors to support TEA s trading activities is an amount not to exceed approximately $96 million. If payment is required to be made, it will be treated as an operation and maintenance expense. Colectric Partners The Authority is also a member of Colectric Partners ( Colectric ). Colectric provides public power utilities with key project and business management resources. Colectric s member participants are: the Authority, Florida Municipal Power Agency, Gainesville Regional Utilities, JEA, Lansing Board of Water & Light, MEAG Power, Nebraska Public Power District and Orlando Utilities Commission. Colectric specializes in the development, project management, operations and maintenance of public power utilities electric generation and gas infrastructure facilities. Currently, the Authority participates in two of Colectric s initiatives. The first involves managing the major gas turbine overhauls thereby promoting the sharing of spare parts and technical expertise. The second initiative is a supply chain management initiative intended to achieve major cost savings through volume purchasing leverage. 21

26 RATES AND RATE COMPARISON Rates The Authority's Board of Directors is empowered and required to set rates as necessary, except for wholesale transmission rates, to provide for expenses, including debt service, of the Authority. The Authority's current rates for customers other than Central were adopted by the Authority's Board of Directors on January 22, 1996 and became effective April 1, From time to time, the Authority s Board of Directors has revised certain of its rates schedules. The Authority has developed and offers time-of-use, nonfirm and off-peak rates to its direct-served commercial and industrial customers to encourage them to reduce their peak demand. As of December 31, 2005, the Authority had 737 MW of non-firm power under contract. The Authority's rate schedules include fuel adjustment clauses which provide for increases or decreases to the basic rate schedules to cover increases or decreases in the cost of fuel to the extent such costs vary from a predetermined base cost. The Authority's rate schedules also include a demand sales adjustment clause which provides for increases or decreases to the basic rate schedules to reflect increases or decreases in demand revenues from non-firm sales (such as interruptible and economy power rate schedules and riders) and offsystem sales, which are credits to firm customers' rates, to the extent such credits vary from predetermined base amounts. Rates under the Central Agreement, as amended, are determined in accordance with the cost of service methodology contained in the Central Agreement. During 2005 revenues from sales to wholesale requirements customers averaged 5.19 cents per kwh, revenues from sales to large industrial customers averaged 4.56 cents per kwh, and revenues from sales to residential, commercial, small industrial and other customers averaged 7.56 cents per kwh based on the then current rates which included fuel adjustments and credits for demand sales adjustments. 22

27 Rate Comparison A comparison of the Authority s average monthly bills at selected usage levels with the average monthly bills of the three investor-owned utilities that serve in the State, based on rates on file with the South Carolina Public Service Commission (the PSC ) as of October 1, 2006, is set forth below. Residential Electric Service 500 kwh 1,000 kwh 2,000 kwh 3,000 kwh Authority... $49.93 $93.01 $ $ Duke Energy Carolinas Progress Energy Carolinas South Carolina Electric & Gas Company Commercial Electric Service 3,000 kwh 5,000 kwh 7,500 kwh Authority... $ $ $ Duke Energy Carolinas Progress Energy Carolinas South Carolina Electric & Gas Company ,000 kw 500,000 kwh Industrial Electric Service 2,000 kw 1,000,000 kwh 9,000 kw 5,000,000 kwh 40,000 kw 25,000,000 kwh Authority... $32, $62, $299, $1,439, Duke Energy Carolinas... 25, , , ,069, Progress Energy Carolinas... 33, , , ,485, South Carolina Electric & Gas Company... 29, , , ,298,

28 Historical Demand, Sales and Revenues HISTORICAL SALES The following table sets forth the territorial peak demand including firm off-system sales to other utilities, if any, on the Authority's System as well as the million kwh ( GWh ) sales and electric revenues of the Authority for the years 1996 through Peak Demand(1) Sales Revenue From Sales Annual Annual Amount Annual Cents Increase Increase (Dollars in Increase Per MW (Decrease) GWh (Decrease) Thousands) (Decrease) kwh , , , ,450 (2.6) 18, , , , , , , , , , , , , , ,817 (0.1) 24, ,019, , , ,033, ,111 (5.3) 24, ,136, , , ,335, Annual Compound Growth Rate ( ) (1) Includes firm off-system sales to other utilities. The following tables set forth sales and revenues by customer class for the years 2001 through Sales (GWh) Year Class of % of % of % of % of % of Customers Total Total Total Total Total Wholesale... 11, , , , , Large Industrial... 7, , , , , Residential, Commercial, Small Industrial and Other... 3, , , , , Total... 22, , , , , Revenues (Dollars in Thousands) Year Class of % of % of % of % of % of Customers Total Total Total Total Total Wholesale... $498, $ 545, $ 544, $ 604, $ 705, Large Industrial , , , , , Residential, Commercial, Small Industrial and Other , , , , , Total... $955, $1,019, $1,033, $1,135, $1,335,

29 FINANCIAL INFORMATION Historical Operating Results A summary of the Authority's revenues available for debt service, lease payments and other purposes for years 2001 through 2005 is set forth below: Calendar Year (Dollars in Thousands) Operating Revenues... $1,350,081 $1,151,009 $1,047,934 $1,033,335 $973,039 Other Income(1)... 28,471 11,175 10,408 16,902 21,071 Total... $1,378,552 $1,162,184 $1,058,342 $1,050,237 $994,110 Operating Expenses (except depreciation) , , , , ,675 Revenues Available for Debt Service, Lease Payments and Other Purposes(1) , , , , ,435 Debt Service on Original Bonds(2) ,283 4,557 4,543 4,529 Balance Available for Revenue Bonds, Revenue Obligations, Lease Payments and Other Purposes , , , , ,906 Debt Service on Revenue Bonds... 40,436 61,403 80, , ,164 Balance Available for Revenue Obligations, Lease Payments and Other Purposes , , , , ,742 Debt Service on Revenue Obligations , , ,001 75,434 28,168 Balance Available for Lease Payments and Other Purposes , , , , ,574 Debt Service on Lease Payments... 3,597 3,700 3,810 3,818 3,818 Balance Available for Other Purposes $ 215,141 $ 179,618 $ 177,442 $ 178,775 $161,756 Debt Service Coverage(3): Original Bonds, Revenue Bonds, Revenue Obligations and Lease Payments (1) Does not include gains on sale of leased lots or rail cars. (2) This series of bonds is no longer outstanding. (3) Calculation of coverage does not include debt service on Commercial Paper Notes. 25

30 CAPITAL IMPROVEMENT PROGRAM General The Authority's capital improvement program for years 2006 through 2008 consists of expenditures for construction of Cross Units 3 and 4, Pee Dee Unit 1, a future nuclear unit and general improvements to the Authority's System, including improvements to existing power supply facilities, extensions of and improvements to transmission and distribution facilities, environmental compliance, and other improvements to general facilities. The total cost of the capital improvement program in years 2006 through 2008 is estimated to be approximately $1,765,000,000, which includes $762,000,000 for Cross Units 3 and 4, $296,000,000 for Pee Dee Unit 1, $31,000,000 for a future nuclear unit, approximately $166,000,000 for environmental compliance expenditures, and approximately $510,000,000 for general improvements to the System. The cost of the capital improvement program will be provided from Revenues of the Authority, additional Revenue Obligations, and Commercial Paper Notes and other short-term obligations of the Authority, as determined by the Authority. See CAPITAL IMPROVEMENT PROGRAM -- Long-Term Power Supply Plan. Long-Term Power Supply Plan The Authority s overall power supply objective is to continue to satisfy the electric power and energy needs of its customers with economical and reliable service. The Authority reviews, from time to time, its power resources and requirements and considers the possible addition of new power resources, which may include nuclear, natural gas, oil and coal fired units, as well as long-term power purchase agreements. An update of the generation resource plan was completed in 2006 which includes the addition of new Authority capacity described under CAPITAL IMPROVEMENT PROGRAM -- Cross Unit 3, CAPITAL IMPROVEMENT PROGRAM -- Cross Unit 4, CAPITAL IMPROVEMENT PROGRAM -- Pee Dee Unit 1 and CAPITAL IMPROVEMENT PROGRAM -- Future Nuclear Unit. Cross Unit 3 In September 2001, the Authority s Board of Directors approved the construction of Cross Unit 3, a 580 MW (net) pulverized coal-fired unit. The new unit will be located at the existing Cross Generating Station in Berkeley County, South Carolina. The planned commercial operation date is January In addition to the equipment required for the new unit, common equipment required for a new unit, Cross Unit 4, will be installed during Cross Unit 3 construction. This will facilitate build-out of the site originally configured for four units. Worley Parsons is the Architect/Engineer for this project. The construction permit has been received and construction is approximately 96% complete. Cross Unit 4 In February 2004, the Authority s Board of Directors approved the construction of Cross Unit 4, a 580 MW (net) pulverized coal-fired unit. The new unit will be located at the existing Cross Generating Station in Berkeley County, South Carolina. The planned commercial operation date is January The unit is to be a duplicate of Cross Unit 3 presently under construction. Worley Parsons is the Architect/Engineer for this project. The construction permit has been received and construction is approximately 28% complete. Pee Dee Unit 1 In May 2006, the Authority s Board of Directors approved the construction of Pee Dee Unit 1, a 600 MW (net) supercritical pulverized coal-fired unit. The new unit will be located on land purchased by the Authority in the early 1980 s along the Great Pee Dee River in Florence County. The planned commercial operation date is January 2012, subject to permitting. Worley Parsons has been retained as the Architect/Engineer for this project. 26

31 Future Nuclear Unit The Authority and SCE&G previously announced they will consider the possibility of constructing a new, jointly owned nuclear generation facility and sent a letter to the Nuclear Regulatory Commission ("NRC") on December 6, 2005, stating their intent to file a combined construction and operating license application. On October 20, 2006, the Authority s Board of Directors authorized management to expend up to $390,000,000 through 2010 in continuing actions necessary to design, permit, procure, construct and install two 1100 MW units at Summer Nuclear Station. This authorization includes $31,000,000 previously included in the capital improvement program for 2006 through Construction may not commence until the Board of Directors has approved a final budget and construction schedule. The Authority and SCE&G have entered into a short term Bridge Agreement which contemplates an Authority ownership interest of 45% in the two units and governs the relationship of the Authority and SCE&G while proceeding toward obtaining a construction and operating license. The Authority anticipates the Bridge Agreement will be replaced by more permanent agreements governing construction, operation and decommissioning of the units. The Bridge Agreement allows either or both parties to withdraw from the project under certain circumstances. Landfill Sites In addition to the new Cross coal-fired units, the Authority has entered into an agreement with Anderson Regional Landfill, LLC to install and operate methane gas-fired electric generating units at the Anderson Regional Landfill. Initial capability is expected to be approximately 5 MW with potential future expansion. The commercial operation date for Anderson Regional Stations is the fourth quarter of General Improvements The Authority's general improvement program consists primarily of extensions and improvements to the Authority's existing generating facilities, transmission and distribution systems, and general plant. Regional Water Systems Pursuant to the Act, the Authority is permitted to construct, own and operate facilities to treat, transmit and sell potable water at wholesale within the counties of Berkeley, Calhoun, Charleston, Clarendon, Colleton, Dorchester, Orangeburg and Sumter, South Carolina. The Authority currently owns and operates a regional water system with a treatment plant capacity of 31 million gallons per day. The system sells water at wholesale to the Lake Moultrie Water Agency, a joint municipal water system consisting of four governmental entities. Under current State law and by contract the water system must be self supporting. Calhoun, Clarendon, Dorchester, Orangeburg and Sumter Counties as well as the municipalities of Elloree, Holly Hill, Manning, Santee, St. George and Summerton have formed the Lake Marion Regional Water Agency to develop a regional water system to serve portions of each of the five counties. Under current State law and by contract such a system would be required to be self supporting. The Lake Marion Regional Water Agency has secured $39.4 million in State and federal grants and anticipates having contracts with county and municipal customers. The Authority is facilitating development of the water system and will own and operate the Lake Marion water system. The Electric Utility Industry Generally COMPETITION The electric utility industry in general has been affected by regulatory changes, market developments and other factors which have impacted, and will probably continue to impact, the financial condition and competitiveness of electric utilities and the level of utilization of facilities, such as those of the Authority. 27

32 In addition to the factors discussed below, such factors include, among others, (a) effects of compliance with rapidly changing environmental, safety, licensing, regulatory and legislative requirements, (b) changes resulting from conservation and demand-side management programs on the timing and use of electric energy, (c) changes that might result from national energy policies, (d) effects of competition from other electric utilities (including increased competition resulting from mergers, acquisitions, and strategic alliances of competing electric (and gas) utilities and from competitors transmitting less expensive electricity from much greater distances over an interconnected system) and new methods of producing low cost electricity, (e) increased competition from independent power producers, marketers and brokers, (f) self-generation by certain industrial and commercial customers, (g) issues relating to the ability to issue tax-exempt obligations, (h) restrictions on the ability to sell to nongovernmental entities electricity from projects financed with outstanding tax-exempt obligations, (i) changes from projected future load requirements, (j) increases in costs, and (k) shifts in the availability and relative costs of different fuels. Any of these factors (as well as other factors) could have an effect on the financial condition of any given electric utility, including the Authority, and likely will affect individual utilities in different ways. Historically, electric utilities have operated as monopolies in their service areas, subject to certain exceptions. Under this regulatory regime, electric utilities have generally been able to charge rates determined by reference to their costs of service, rather than by competitive forces, and customers of an electric utility with high rates have not been allowed to purchase power at lower rates from other electric utilities. In contrast, in a deregulated market, it is anticipated that customers in a particular service area will be permitted to choose among competing electric suppliers, resulting in a market price for electric power in that service area. An electric utility with power costs that are high in relation to the power costs of competing electric utilities may have costs that cannot be recovered by charging the market rate. Although certain deregulation measures proposed to date would allow for recovery of some portion of the costs that would otherwise be nonrecoverable when markets are deregulated, the ultimate regulatory treatment of such costs cannot be predicted. The loss of customers by an electric utility, particularly in the absence of a method to recover costs allocable to such customers, could have a material adverse effect on the financial condition of the utility. The Authority cannot determine with certainty what effects such factors will have on its business operations and financial condition, but the effects could be significant. Extensive information on the electric utility industry is available from sources in the public domain, and potential purchasers of the 2006M Bonds should obtain and review such information. Changes in Federal Regulation of Electric Utilities The Energy Policy Act of 1992 ( EPACT 1992 ) made fundamental changes in the federal regulation of the electric utility industry, particularly in the area of transmission access, which have had a significant impact on the wholesale power market. In response to EPACT 1992 on April 24, 1996, the FERC issued Orders 888 and 889 implementing rules for mandatory non-discriminatory open access over the transmission systems of jurisdictional transmission owners. Order 888 required each jurisdictional transmission owner to file with FERC by July 9, 1996 a proforma open access transmission tariff ( OATT ) and that a non-jurisdictional transmission owner, such as the Authority, must agree to provide comparable transmission service over its transmission facilities in order to receive service from a jurisdictional transmission owner under its OATT. The stated purpose of Orders 888 and 889 is to remove perceived impediments to competition in the wholesale bulk power market and to bring more efficient, lower-cost power to the nation s electric consumers. Seeking to remove additional impediments to wholesale competition, on December 20, 1999 the FERC issued Order 2000, its Final Rule on Regional Transmission Organizations ( RTOs ). Order 2000 contemplates RTOs as voluntary participation associations of power transmission owning entities comprising public and non-public utility entities, which would more efficiently address operational and reliability issues confronting the industry in particular by improving grid reliability, increasing efficiencies in transmission grid management, preventing discriminatory practices and improving market performance. 28

33 On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005 ( EPACT 2005 ). EPACT 2005 reflects a further refinement in federal energy policy but, unlike EPACT 1992, does not represent a fundamental change from the immediate past. EPACT 2005 introduces a new Section 211A of the Federal Power Act ( FPA ), Open Access by Unregulated Transmitting Utilities. Under Section 211A, FERC has authority to require an otherwise nonjurisdictional transmission owner, such as the Authority, owning or operating transmission facilities to provide transmission services at (1) rates that are comparable to those they charge themselves, and (2) terms and conditions that are comparable to those they charge themselves and that are not unduly discriminatory or preferential. EPACT 2005 also introduces a new Section 217 of the FPA, Native Load Service Obligation. Under this provision, any load-serving entity with a service obligation, including an otherwise nonjurisdictional transmission owner, is entitled to use its transmission capacity to meet its native load service obligation in preference to other uses of the grid. A service obligation is defined by Section 217 to mean a requirement applicable to a utility under federal, state, or local law, or under a long-term contract to provide electric service to end users or to a distribution utility. The statutory right that an otherwise non-jurisdictional transmission owner has to use its transmission facilities to serve native load qualifies the obligation it has to provide open access transmission service under Section 211A. Finally, EPACT 2005 introduces a new Section 215 of the FPA which authorizes the FERC to certify an entity to be the nation s Electric Reliability Organization ( ERO ) that would propose reliability standards that would be reviewed by FERC before becoming final as well as enforcing those standards. All users, owners and operators of the bulk power system, including an otherwise non-jurisdictional transmission owner, must comply with the standards. The ERO and FERC may impose penalties for non-compliance. The ERO may delegate to a regional entity the authority to enforce reliability standards. States may take action to ensure reliability, as long as such action is not inconsistent with a reliability standard approved by FERC. On July 20, 2006, the FERC issued an order certifying the North American Electric Reliability Corporation as ERO. On May 19, 2006, the FERC issued a Notice of Proposed Rulemaking ( NOPR ) to amend the regulations adopted in Order Nos. 888 and 889, and to the pro forma OATT. The purpose of the rulemaking is to ensure that the OATT achieves its original purpose, namely, that transmission services are provided on a basis that is just, reasonable and not unduly discriminatory or preferential. This is the FERC s first comprehensive review of Orders 888 and 889 since these orders were issued in A Final Rule modifying Orders 888 and 889 is expected to be issued the Spring of Regional Transmission Organizations Presently there are no active RTO development activities in the southeastern United States. Two previous efforts to develop a RTO for the Southeastern United States resulted in failure. In each case, the Authority believes, the effort failed because of the lack of demonstrable benefits from forming a RTO and the lack of consensus support and acceptance from all applicable state and federal agencies for the proposed RTO structure. Whether a new RTO development effort will arise in the Southeastern United States is unknown at this time. Any potential impact on the Authority of such a new effort is likewise unknown. FERC Matters REGULATORY MATTERS The Authority operates its Jefferies Hydro Station and certain other property, including the Pinopolis Dam on the Cooper River and the Santee Dam on the Santee River, which are major parts of the Authority s integrated hydroelectric complex, under a license issued by the FERC pursuant to the Federal Power Act. The project is currently undergoing relicensing and a Notice of Intent to relicense was filed with the FERC on November 13, The preliminary license application was submitted to stakeholders for review in March 2003 and the final license application was submitted March 12, Due to a number of Additional 29

34 Information Requests ( AIR ), the relicensing process has extended beyond the license expiration date therefore, the FERC has issued a standing annual license renewal until a final license is issued. The FERC issued a Ready for Environmental Analysis ( REA ) notice in March The FERC also has revised its National Environmental Policy Act ( NEPA ) scoping document from an Environmental Assessment ( EA ) to an Environmental Impact Statement ( EIS ) due in part to the size and complexity of the Authority project. The schedule for final license renewal prior to the EA to EIS revision was projected by the FERC to be by the end of calendar year As required under the Authority s hydropower license with the FERC, an eighth Part 12 Dam Safety Inspection was completed and submitted to the FERC in March No significant concerns were identified during the inspection of the hydroelectric complex. Environmental Matters Both federal and State regulatory agencies have imposed various environmental control requirements affecting the Authority s facilities. These requirements relate primarily to airborne pollution, the discharge of pollutants (including heat) into waters and the disposal of hazardous wastes. Standards related to environmental controls are subject to change, and litigation by environmental groups and others may affect the construction of facilities or their operation. The Authority endeavors to insure that its facilities comply with applicable environmental regulations and standards; however, no assurance can be given that normal operations will not encounter occasional technical difficulties, or that necessary authorizations and permits will be received, or that standards as to environmental suitability will not be changed in a manner which will affect adversely the Authority or its operations. The Authority cannot now estimate the precise effect of existing and potential regulations and legislation upon any of its existing and proposed facilities and operations, nor the impact of additional costs which may be incurred in effecting compliance with potential regulations and legislation. Air Quality. Pursuant to the Clean Air Act ( CAA ), as amended, the EPA promulgated primary and secondary national ambient air quality standards with respect to certain air pollutants, including particulate matter, SO 2 and nitrogen oxide ( NOx ). These standards are to be achieved by the application of control strategies developed by the states and included in implementation plans which must be approved by the EPA to become effective. The South Carolina Department of Health and Environmental Control ( DHEC ) has adopted a State Implementation Plan ( SIP ), which has been approved by the EPA, generally designed to achieve the primary and secondary air quality standards. The EPA has promulgated the New Source Performance Standards ( NSPS ) regulations establishing stringent emission standards for particulate matter, SO 2 and NOx emissions for fossil-fuel fired steam generators, the construction of which commenced after August 17, 1971, or which after such date are modified in such a way as to have the potential to significantly increase emissions of regulated air pollutants. In addition, in June 1979 the EPA promulgated revised NSPS regulations for electric utility steam generating units which apply to units on which construction commenced after September 18, These standards not only provide for more stringent particulate, NOx and SO 2 emission limits than the previous standards, but also specify SO 2 emissions compliance, SO 2 removal efficiency, NOx emissions compliance, emissions monitoring, and reporting requirements on a 30 day rolling average basis. In May 2005 the EPA revised this NSPS to establish mercury emission standards and monitoring requirements for new and modified sources that are subject to this standard. The EPA also revised the NSPS regulations establishing more stringent emissions standards and monitoring requirements for SO 2 and NOx for combustion turbines which commenced construction, modification, or reconstruction after October 3, The EPA recently promulgated two Clean Air regulations: Clean Air Interstate Rule (the CAIR ) and Clean Air Mercury Rule (the CAMR ). The CAIR, which addresses SO 2 and NOx emissions, was published in the federal register May 12, 2005 and took effect July 11, The CAMR was published May 18, 2005 and took effect July 18, The Authority is currently evaluating the effect of these rules on its existing facilities and operations. In addition, the Authority, along with other utilities, has challenged the SO 2 allocation portion of the CAIR. The Authority is currently participating in the stakeholders process initiated by DHEC, the purpose of which is to propose regulations to the legislature regarding a SIP for the CAIR and the CAMR in South Carolina. 30

35 The EPA has promulgated regulations designed to prevent significant deterioration ( PSD ) of air quality in portions of a state where air quality is now better than the National Ambient Air Quality Standards ( NAAQS ). Winyah Units 3 and 4, Cross Station, Rainey Station, Hilton Head Turbine No. 3 and the Lee County Landfill Generation Facility are subject to and, the Authority believes, are in compliance with the PSD regulations. Subsequently completed generating facilities will also be subject to the PSD regulations. The Authority has obtained operating permits for each of its existing generating facilities and believes these facilities are operating in compliance with the requirements of the permits. The Authority has applied to DHEC for the renewal of the Title V operating permits for the Cross, Winyah, Grainger and Jefferies Generating Stations. The Hilton Head and Myrtle Beach Turbine site Title V operating permits were renewed and issued December 21, 2005 and became effective April 1, The Rainey Generating Station initial Title V operating permit was issued July 5, 2005 and was effective October 1, The Authority obtained a Title V operating permit for its first landfill gas to energy ( LFGTE ) facility at the Horry County landfill and construction permits for the Lee, Richland and Anderson County LFGTE facilities. A Title V application is currently being reviewed by DHEC for the Lee County LFGTE facility. Conditional major operating permits were obtained for the six diesel engine sites. Congress has enacted comprehensive amendments to the 1990 CAA, including the addition of a new federal Acid Rain program to deal with acid precipitation. The Authority has evaluated the potential impact of this legislation, including new limits on the allowable rates of emission of SO 2 and NOx beginning in 2000 for boilers. To comply with these regulations, the Authority has purchased SO 2 emission credits and upgraded the sulfur removal capabilities of existing units to meet SO 2 emission limitations. To meet acid rain NOx limits, the Authority has also retrofitted the combustion systems on some of its boilers and implemented both an Alternative Emissions Limit Program and a System Averaging Program to meet NOx limitations. In addition, the Authority has installed continuous emission monitoring equipment to comply with monitoring requirements. The EPA in 1998 issued regulations creating more demanding limits on NOx emissions in 22 eastern states, including South Carolina, and issued a call for revised SIP to meet the more stringent emission requirements. The EPA approved the State s NOx SIP plan on June 28, 2002, and it is now in effect. As a result, the Authority s cost of compliance, including capital costs, have been $265,749,048 through August 31, Annual operating costs associated with such compliance are estimated to be between $10 - $15 million. See CAPITAL IMPROVEMENT PROGRAM. The CAA requires that air quality in every state meet health based NAAQS. In 1997, the EPA promulgated a more stringent 8-hour ozone standard to replace the 1-hour standard. The State submitted compact agreements to EPA in December 2002, called Early Action Compacts ( EAC ) pledging to meet the 8-hour ozone standard earlier than required. The areas with EACs had to meet a number of criteria, and had to agree to meet certain milestones. In April 2004, EPA Region 4 designated the non-attainment areas in the State, which included counties that affect some of the Authority s facilities. However, as long as EAC areas meet agreed upon milestones, the impact of the designations will be deferred. DHEC is currently evaluating controls and/or required pollutant reductions needed for these areas to meet attainment. The Authority is following this development and is evaluating the impact from these new ozone standards. The same 1997 NAAQS regulation also addressed particulate matter NAAQS for 2.5 microns or less ( PM 2.5 ). Based on monitoring data collected from , DHEC reported to EPA in February 2004, that the State fully complies with the annual and 24-hour NAAQS PM 2.5. Therefore, DHEC recommended the entire State be designated as in attainment for the PM 2.5 standards. As of December 2004, EPA had no counties in the State designated as non-attainment for PM 2.5 in the State. Greenville County, South Carolina was classified as unclassifiable and is to be evaluated for further study. The EPA announced September 21, 2006 that it is revising the NAAQS to tighten the daily standard on PM 2.5. The new rule on PM 2.5 will go into effect in It will lower the 24-hour standard for PM 2.5 to 35 micrograms per cubic meter, nearly cutting in half the current standard of 65 micrograms per cubic meter. The annual standard for PM 2.5 will remain at the level the agency set in

36 Water Quality. The Federal Water Pollution Control Act, renamed in 1977 the Clean Water Act ( CWA ), prohibits the discharge of pollutants, including heat, from point sources into waters of the United States, except as authorized in the National Pollutant Discharge Elimination System ( NPDES ) permit program. The CWA also requires that cooling water intake structures reflect the best technology available for minimizing adverse environmental impact. DHEC has been delegated NPDES permitting authority by the EPA and administers the program for the State. DHEC has stated that if there should be a delay in renewing permits beyond the expiration of the existing permits, the permits will be extended by operation of law and the Authority may still discharge pursuant to Section of the Code of Laws of South Carolina 1976, as amended. Each station s stormwater discharge is covered under the State s NPDES General Permit No. SCR The Authority believes it is in compliance with this permit. Industrial wastewater discharges from all stations are governed by individual NPDES permits. The Cross Generating Station NPDES permit was reissued effective August 1, 2000, with an expiration date of July 31, This permit was modified December 1, 2003, to authorize the additional discharge that will result when Cross Unit 3, which is currently under construction, becomes operational. An application for renewal of the Cross Generating Station NPDES permit was submitted on February 1, The Grainger Generating Station NPDES permit was reissued effective October 1, 2002, with an expiration date of September 30, An application for renewal of the Grainger Generating Station NPDES permit was submitted on March 28, The Jefferies Generating Station NPDES permit was reissued effective March 1, 2003, with an expiration date of February 29, The Winyah Generating Station NPDES permit was reissued effective October 1, 2000, with an expiration date of September 30, An application for renewal of the Winyah Generating Station NPDES permit was submitted on March 29, The Rainey Generating Station NPDES permit was reissued effective August 1, 2003, with an expiration date of July 31, The Authority s Regional Water System s NPDES permit was reissued effective October 1, 2001 with an expiration date of October 31, An application for renewal was submitted April 24, The EPA revised sections of the CWA relating to Spill Prevention Control and Counter- measures ( SPCC ). These revisions require that regulated facilities amend their current SPCC plans to meet the new standard. The Authority is in the process of compliance with the new standard before the regulatory required implementation date of October 31, The EPA published regulations implementing Section 316(b) of the CWA for existing electric generating facilities in the Federal Register on July 9, These regulations require that cooling water intake structures reflect the Best Technology Available ( BTA ) for minimizing adverse environmental impacts such as the impingement of fish and shellfish on the intake structures and the entrainment of eggs and larvae through cooling water systems. These regulations, which became effective September 7, 2004, establish performance standards for reduction in impingement mortality and entrainment. The Jefferies Generating Station and the Grainger Generating Station are the Authority s only facilities affected by the new rule, and are currently in compliance with the requirements. Hazardous Substances and Wastes. Section 311 of the CWA imposes substantial penalties for spills of Federal EPA-listed hazardous substances into water and for failure to report such spills. The Comprehensive Environmental Response, Compensation, and Liability Act of 1980 ( CERCLA or Superfund ) provides for the reporting requirements to cover the release of hazardous substances generally into the environment, including water, land and air. When these substances are processed, stored, or handled, reasonable and prudent methods are employed to prevent a release to the environment. Additionally, the EPA regulations under the Toxic Substances Control Act impose stringent requirements for labeling, handling, storing and disposing of polychlorinated byphenyls ( PCBs ) and associated equipment. There are regulations covering PCB notification and manifesting, restrictions on disposal of drained electrical equipment, spill cleanup record-keeping requirements, etc. The Authority has implemented a comprehensive PCB management program in response to these regulations. Under the CERCLA and Superfund Amendments and Reauthorization Act ( SARA ), the Authority could be held responsible for damages and remedial action at hazardous waste disposal facilities utilized by it, 32

37 if such facilities become part of a Superfund effort. CERCLA liability, which is strict, joint and several, can be imposed on any generator of hazardous substances who arranged for disposal or treatment at the affected facility. Moreover, under SARA, the Authority must comply with a program of emergency planning and a Community Right-To-Know program designed to inform the public about more routine chemical hazards present at the facilities. Both programs have stringent enforcement provisions. The Authority endeavors to comply with the applicable provisions of CERCLA and SARA, but it is not possible to determine if some liability may be imposed in the future for past waste disposal or compliance with new regulatory requirements. In addition to handling hazardous substances, the Authority generates solid waste associated with the combustion of coal, the vast majority of which is fly ash, bottom ash and scrubber sludge. These wastes are exempt from hazardous wastes regulation under the Resource Conservation and Recovery Act ( RCRA ). Also under RCRA, the Authority may be required to undertake corrective action with respect to any leaking underground petroleum storage tank and is liable for the costs of any corrective action taken by the EPA, including compensating third parties for personal injuries and property damage. The Authority implemented a program which assessed all underground storage tanks ( USTs ). As a result of the assessment, the number of USTs has been significantly reduced. The Authority is required by the EPA and DHEC to maintain documentation of sufficient funds or insurance to cover environmental impacts. Moreover, certain waste including boiler cleanings, waste solvents and waste oils may be considered hazardous wastes. The Authority endeavors to maintain compliance with the RCRA and South Carolina Hazardous Waste Management regulations and believes its facilities are currently operating substantially in compliance with the regulations. It should be noted that the State s waste laws are sometimes more stringent than federal laws. In light of the more stringent RCRA amendments, it is not possible to predict whether the State will adopt regulations consistent with, or more stringent than, federal law. Nuclear Matters The Summer Nuclear Station is subject to regulation by the NRC. SCE&G and the Authority were required to obtain liability insurance and a United States Government indemnity agreement for the Summer Nuclear Station in order for the NRC operating license to be issued. This primary insurance and the retrospective assessment are to insure against the maximum liability under the federal Price-Anderson Act for any public claims arising from a nuclear incident. The Energy Policy Act of 2005 extends the Price-Anderson Act until The NRC requires that a licensee of a nuclear reactor provide minimum financial assurance of its ability to decommission its nuclear facilities. In compliance with the applicable NRC regulations, the Authority established an external trust to comply with the new regulations. The Authority began making deposits into the external decommissioning fund in September In addition to providing for the minimum requirements imposed by the NRC, the Authority established in 1983 an internal decommissioning fund. Based on the most recent decommissioning cost estimates developed by SCE&G, both the internal and external funds, which had a combined market value of approximately $123 million at December 31, 2005, along with future deposits and investment earnings, are estimated to provide sufficient funds for the Authority's one-third share of the total estimated decommissioning costs. 33

38 LITIGATION AND OTHER MATTERS Litigation No litigation is now pending or, to the knowledge of the Authority, threatened, questioning the corporate existence of the Authority or the right of its officers to their respective offices or the right of the Authority to fix rates and other charges for the sale of electric energy, or questioning the right of the Authority to issue the 2006M Bonds. Except as noted below, there are no actions, suits, or governmental proceedings pending or, to the knowledge of the Authority, threatened before any court, administrative agency, arbitrator or governmental body which would, if determined adversely to the Authority, have a material adverse effect on its financial condition. However, even if determined adversely to the Authority, no such actions, suits, or governmental proceedings would have a material adverse effect on the Authority s ability to transact its business or meet its obligations under the Revenue Obligation Resolution. An action was instituted in the U.S. District Court, Charleston, South Carolina, by a number of landowners located along the Santee River primarily in Williamsburg and Georgetown Counties, South Carolina. The plaintiffs contend, through various causes of action, that the Authority is liable to them for damage to their real estate as a result of flooding that has occurred since the U.S. Army Corps of Engineers Cooper River Rediversion Project was completed in A trial was held in the case from February 18, 1997 through March 6, 1997 to determine liability. The jury returned its verdict against the Authority on certain causes of action. The jury s verdict was sustained by the judge in a ruling on post-trial motions dated July 14, The Authority appealed the decision to the Fourth Circuit of Appeals which, after oral arguments, remanded the case to the District Court. The Corps recently moved to intervene and transfer the District Court action to the Court of Federal Claims. The Authority joined in this motion. The District Court denied the motion and the issue is on appeal to the United States Court of Appeals for the Federal Circuit. No estimate relative to potential loss to the Authority can be made at this time. The U. S. Army Contract Board of Appeals has determined that the contract between the Corps and the Authority requires that the Corps indemnify the Authority for certain claims arising out of the construction and operation of the project. Certain plaintiffs who are customers of members of Central filed suit against the Authority and members of Central seeking monetary damages arising out of a change in the Good Cents rate. The plaintiffs sought to represent a class of all Good Cents customers of Central s members. The Authority answered the complaint by denying the material allegations and opposing the request for class certification. The parties reached a settlement which has been approved by the court. The settlement has no material adverse impact on the Authority. Other Matters In July 2000 the Authority received a request for information from the EPA pursuant to Section 114 of the CAA. The Authority received an additional request for information from the EPA in December The requests are part of EPA s ongoing enforcement initiative involving the power generating sector, with particular emphasis on coal fired units. In May 2003, the Authority received notice that DHEC and EPA were also investigating an alleged violation of the CAA involving Cross Generating Station. The Authority responded to the requests for information, and on March 16, 2004, the Authority, EPA and DHEC agreed on the terms of a settlement regarding these issues. The settlement was approved by the U.S. District Court for South Carolina and a Consent Decree was entered on June 24, The settlement involves the payment of a civil penalty, an agreement to perform certain environmentally beneficial projects, and the expenditure of capital costs of approximately $205,300,000 to achieve emissions reductions over the period ending These capital costs are expected to be largely offset by savings resulting from a reduced need to purchase emission credits. 34

39 FINANCIAL ADVISOR The Authority has retained Lehman Brothers of New York, New York, as Financial Advisor in connection with the issuance of the 2006M Bonds. Federal Income Tax Generally TAX MATTERS On the date of issuance of the 2006M Bonds, Haynsworth Sinkler Boyd, P.A., Charleston, South Carolina ( Bond Counsel ), will render an opinion that, assuming continuing compliance by the Authority with the requirements of the Internal Revenue Code of 1986, as amended (the Code ), and the applicable regulations promulgated thereunder (the Regulations ) and further subject to certain considerations described in Collateral Federal Tax Considerations below, under existing statutes, regulations and judicial decisions, interest on the 2006M Bonds is excludable from the gross income of the registered owners thereof for federal income tax purposes. Interest on the 2006M Bonds will not be treated as an item of tax preference in calculating the alternative minimum taxable income of individuals or corporations; however, interest on the 2006M Bonds will be included in the calculation of adjusted current earnings in determining the alternative minimum tax liability of corporations. The Code contains other provisions that could result in tax consequences, upon which no opinion will be rendered by Bond Counsel, as a result of (i) ownership of the 2006M Bonds or (ii) the inclusion in certain computations (including, without limitation those related to the corporate alternative minimum tax) of interest that is excluded from gross income. The opinion of Bond Counsel will be limited to matters relating to the authorization and validity of the 2006M Bonds and the tax-exempt status of interest on the 2006M Bonds as described herein. Bond Counsel makes no statement regarding the accuracy and completeness of this Official Statement. The opinion of Bond Counsel is based on current legal authority, covers certain matters not directly addressed by such authorities, and represents Bond Counsel's judgment as to the proper treatment of the 2006M Bonds for federal income tax purposes. Bond Counsel's opinions are based upon existing law, which is subject to change. Such opinions are further based on factual representations made to Bond Counsel as of the date thereof. Bond Counsel assumes no duty to update or supplement its opinions to reflect any facts or circumstances that may thereafter come to Bond Counsel's attention or to reflect any changes in law that may thereafter occur or become effective. Moreover, Bond Counsel's opinions are not a guarantee of a particular result, and are not binding on the IRS or the courts; rather, such opinions represent Bond Counsel's professional judgement based on its review of existing law, and in reliance on the representations and covenants that it deems relevant to such opinions. The opinion of Bond Counsel described above is subject to the condition that the Authority comply with all requirements of the Code and the Regulations, including, without limitation, certain limitations on the use, expenditure and investment of the proceeds of the 2006M Bonds and the obligation to rebate certain earnings on investments of proceeds to the United States Government, that must be satisfied subsequent to the issuance of the 2006M Bonds in order that interest thereon be, or continue to be, excludable from gross income for federal income tax purposes. The Authority has covenanted to comply with each such requirement. Failure to comply with certain of such requirements may cause the inclusion of interest on the 2006M Bonds in gross income for federal income tax purposes retroactive to the date of issuance of the 2006M Bonds. The opinion of Bond Counsel delivered on the date of issuance of the 2006M Bonds is conditioned on compliance by the Authority with such requirements, and Bond Counsel has not been retained to monitor compliance with the requirements subsequent to the issuance of such 2006M Bonds. 35

40 Collateral Federal Tax Considerations Prospective purchasers of the 2006M Bonds should be aware that ownership of tax-exempt obligations may result in collateral federal income tax consequences to certain taxpayers, including, without limitation, financial institutions, property and casualty insurance companies, life insurance companies, certain foreign corporations, certain S corporations, individual recipients of Social Security or Railroad Retirement benefits and taxpayers who may be deemed to have incurred or continued indebtedness to purchase or carry tax-exempt obligations. Bond Counsel expresses no opinion concerning such collateral income tax consequences, and prospective purchasers of 2006M Bonds should consult their tax advisors as to the applicability thereof. Future legislation, if enacted into law, or clarification of the Code may cause interest on the 2006M Bonds to be subject, directly or indirectly, to federal income taxation, or otherwise prevent owners from realizing the full current benefit of the tax status of such interest. The introduction or enactment of any such future legislation or clarification of the Code may also affect the market price for, or marketability of, the 2006M Bonds. Prospective purchasers of the Series 2006M Bonds should consult their own tax advisers regarding any pending or proposed federal tax legislation, as to which Bond Counsel expresses no opinion. The IRS has established an ongoing program to audit tax-exempt obligations to determine whether interest on such obligations is includable in gross income for federal income tax purposes. Bond Counsel cannot predict whether the IRS will commence an audit of the 2006M Bonds. Bond Counsel s engagement with respect to the 2006M Bonds ends with the issuance of the 2006M Bonds, and, unless separately engaged, Bond Counsel is not obligated to defend the Authority or the owners of 2006M Bonds regarding the tax-exempt status of the 2006M Bonds in the event of an audit examination by the IRS. The IRS has taken the position that, under the standards of practice before the IRS, Bond Counsel must obtain a waiver of a conflict of interest to represent an issuer in an examination of tax exempt bonds for which Bond Counsel had issued an approving opinion. Under current procedures, parties other than the Authority and their appointed counsel, including the owners of 2006M Bonds, would have little, if any, right to participate in the audit examination process. Moreover, because achieving judicial review in connection with an audit examination of tax-exempt bonds is difficult, obtaining an independent review of IRS positions with which the Authority legitimately disagrees, may not be practicable. Any action of the IRS, including but not limited to selection of the 2006M Bonds for audit, or the course or result of such audit, or an audit of bonds presenting similar tax issues may affect the market price for, or the marketability of, the 2006M Bonds, and may cause the Authority or the owners of 2006M Bonds to incur significant expense, regardless of the ultimate outcome. State Tax Exemption Bond Counsel is of the further opinion that the 2006M Bonds and the interest thereon are exempt from all State, county, municipal, school district and other taxes or assessments imposed within the State of South Carolina except inheritance, estate, transfer or certain franchise taxes. Interest paid on the 2006M Bonds is currently subject to the tax imposed on banks by Section , Code of Laws of South Carolina 1976, as amended, which is enforced by the South Carolina Department of Revenue and Taxation as a franchise tax. The opinion of Bond Counsel is limited to the laws of the State of South Carolina and federal tax laws. No opinion is rendered by Bond Counsel concerning the taxation of the 2006M Bonds or the interest thereon under the laws of any other jurisdiction. APPROVAL OF LEGAL PROCEEDINGS Haynsworth Sinkler Boyd, P.A., Charleston, South Carolina, Bond Counsel to the Authority, will render an opinion with respect to the validity and tax treatment of the 2006M Bonds. A copy of such opinion will be attached to the 2006M Bonds and will be in substantially the form set forth in Appendix III. Certain legal matters will be passed upon on behalf of the Authority by James E. Brogdon, Jr., its Senior Vice President and General Counsel. 36

41 MISCELLANEOUS The agreements of the Authority with the owners of the 2006M Bonds are fully set forth in the Revenue Obligation Resolution. This Official Statement is not to be construed as a contract with the purchasers of the 2006M Bonds. Any statements herein involving matters of opinion or estimates, whether or not expressly so stated, are intended merely as such and not as representations of fact. This Official Statement has been approved by the Board of Directors of the Authority. South Carolina Public Service Authority /s/ Lonnie N. Carter President and Chief Executive Officer 37

42 financials Appendix 1 Combined Balance Sheets South Carolina Public Service Authority As of December 31, 2005 and 2004 ASSETS (Thousands) Current assets Unrestricted cash and cash equivalents $ 79,068 $ 38,328 Unrestricted investments 78, ,041 Restricted cash and cash equivalents 136, ,555 Restricted investments 22,323 51,405 Receivables, net of allowance for doubtful accounts of $713 and $595 at December 31, 2005 and 2004, respectively 157, ,114 Materials inventory 56,892 50,776 Fuel inventory Fossil fuels 67,080 33,172 Nuclear fuel-net 15,987 23,324 Interest receivable 1,807 2,044 Prepaid expenses and other current assets 60,959 19,275 Total current assets 676, ,034 Noncurrent assets Unrestricted cash and cash equivalents 62 2,063 Unrestricted investments 54,000 50,110 Restricted cash and cash equivalents 37,901 98,053 Restricted investments 207, ,414 Capital assets Utility plant 4,336,788 4,272,011 Long lived assets - assets retirement cost 93,240 82,846 Accumulated depreciation (1,960,802) ( 1,828,648) Total utility plant-net 2,469,226 2,526,209 Construction work in progress 1,057, ,962 Other physical property-net 2,209 2,088 Investment in associated companies 6,567 6,816 Regulatory asset - asset retirement obligation 153, ,450 Regulatory assets - derivative and hedging instruments Deferred debits and other noncurrent assets Unamortized debt expenses 27,071 28,633 Costs to be recovered from future revenue 246, ,875 Other 46,244 41,730 Total noncurrent assets 4,306,836 4,109,098 Total assets $ 4,983,202 $ 4,686,132 The accompanying notes are an integral part of these combined financial statements. I-1

43 Appendix 1 financials LIABILITIES Current liabilities (Thousands) Current portion of long-term debt $ 69,674 $ 80,994 Accrued interest on long-term debt 63,718 78,456 Commercial paper 285, ,317 Accounts payable 183, ,155 Other current liabilities 92,615 52,654 Total current liabilities 694, ,576 Noncurrent liabilities Construction fund liabilities 48,380 26,824 Asset retirement obligation liability 322, ,613 Total long-term debt (net of current portion) 2,657,160 2,764,450 Unamortized refunding and other costs (138,169) (163,706) Long-term debt - net 2,518,991 2,600,744 Other deferred credits and noncurrent liabilities 61,959 56,196 Total noncurrent liabilities 2,951,688 2,944,377 Total liabilities 3,646,632 3,484,953 NET ASSETS Invested in capital assets, net of related debt 814, ,714 Restricted for debt service 70, ,859 Restricted for capital projects 3,079 18,294 Restricted for other 141, ,608 Unrestricted 306, ,704 Total net assets 1,336,570 1,201,179 Total liabilities and net assets $ 4,983,202 $ 4,686,132 I-2

44 financials Appendix 1 Combined Statements of Revenues, Expenses and Changes in Net Assets South Carolina Public Service Authority Years ended December 31, 2005 and (Thousands) Operating revenues Sale of electricity $ 1,334,754 $ 1,135,786 Sale of water 4,728 4,711 Other operating revenue 10,598 10,512 Total operating revenues 1,350,080 1,151,009 Operating expenses Electric operating expenses Production 65,614 60,359 Fuel 591, ,947 Purchased and interchanged power 117,519 56,114 Transmission 14,192 11,456 Distribution 8,041 7,166 Customer accounts 8,388 8,160 Sales 2,997 3,217 Administrative and general 62,223 62,109 Electric maintenance expense 77,789 78,124 Water operation expense 1,354 1,188 Water maintenance expense Total operation and maintenance expenses 950, ,161 Depreciation and amortization 148, ,475 Sums in lieu of taxes 3,556 3,029 Total operating expenses 1,102, ,665 Operating income $ 247,720 $ 241,344 The accompanying notes are an integral part of these combined financial statements. I-3

45 Appendix 1 financials (Thousands) Nonoperating revenues (expenses) Interest and investment revenue $ 12,952 $ 11,656 Net increase (decrease) in the fair value of investments 4,126 (496) Interest expense on long-term debt (143,562) (141,981) Other interest expense (23,034) (21,883) Costs to be recovered from future revenue 34,374 10,373 Other - net 15,237 3,861 Total nonoperating revenues (expenses) (99,907) (138,470) Income before transfers 147, ,874 Transfers out Distribution to the State (12,422) (11,175) Non-recurring special contribution to State 0 (13,000) Total transfers out (12,422) (24,175) Change in net assets 135,391 78,699 Total net assets-beginning 1,201,179 1,122,480 Total net assets-ending $ 1,336,570 $ 1,201,179 I-4

46 financials Appendix 1 Combined Statements of Cash Flows South Carolina Public Service Authority Years ended December 31, 2005 and (Thousands) Cash flows from operating activities Receipts from customers $ 1,333,354 $ 1,127,858 Payments to non-fuel suppliers (260,791) (84,967) Payments for fuel (586,692) (470,176) Purchased power (117,098) (53,726) Payments to employees (116,951) (110,305) Other receipts, (payments) - net 100,278 20,237 Net cash provided by operating activities 352, ,921 Cash flows from non-capital related financing activities Distribution to the State of South Carolina (12,422) (11,175) Non-recurring special contribution to the State 0 (13,000) Net cash used in non-capital related financing activities (12,422) (24,175) Cash flows from capital-related financing activities Proceeds from sale of bonds 496, ,459 Net commercial paper issuance (repayments) 92,298 (151,852) Repayment and refunding of bonds (612,849) (71,270) Interest paid on borrowings (156,665) (131,853) Construction and betterments of utility plant (440,739) (412,057) Debt premium 11,130 23,277 Other - net (2,994) (6,586) Net cash used in capital-related financing activities (613,003) (269,882) Cash flows from investing activities Net decrease (increase) in investments 247,333 (147,914) Interest on investments 13,173 12,502 Gains on sale of surplus property 10,952 0 Net cash provided by (used in) investing activities 271,458 (135,412) Net (decrease) in cash and cash equivalents (1,867) (548) Cash and cash equivalents - beginning 254, ,547 Cash and cash equivalents - ending $ 253,132 $ 254,999 The accompanying notes are an integral part of these combined financial statements. I-5

47 Appendix 1 financials (Thousands) Reconciliation of operating income to net cash provided by operating activities Operating income $ 247,720 $ 241,344 Adjustments to reconcile operating income to net cash provided by operating activities Depreciation and amortization 153, ,809 Net power gains involving associated companies (45,359) (13,574) Distributions from associated companies 44,164 14,464 Advances to associated companies (97) (1,382) Other income Changes in assets and liabilities Accounts receivable - net (16,608) (23,229) Inventories (40,024) (1,193) Prepaid expenses (38,702) (11,744) Other deferred debits (5,337) (12,548) Accounts payable 44,058 38,654 Other current liabilities 29,369 19,760 Other noncurrent liabilities (20,893) 23,445 Net cash provided by operating activities $ 352,100 $ 428,921 Composition of cash and cash equivalents Current Unrestricted cash and cash equivalents $ 79,068 $ 38,328 Restricted cash and cash equivalents 136, ,555 Noncurrent Unrestricted cash and cash equivalents 62 2,063 Restricted cash and cash equivalents 37,901 98,053 Cash and cash equivalents at the end of the year $ 253,132 $ 254,999 I-6

48 financials Appendix 1 Notes Note 1 Summary of Significant Accounting Policies: A - Reporting Entity The South Carolina Public Service Authority (the Authority or Santee Cooper ), a component unit of the State of South Carolina, was created in 1934 by the State legislature. The Santee Cooper Board of Directors is appointed by the Governor of South Carolina with the advice and consent of the Senate. The purpose of the Authority is to provide electric power and wholesale water to the people of South Carolina. Capital projects are funded by commercial paper in addition to bonds and internally generated funds. As authorized by State law, the Board of Directors sets rates charged to customers to pay debt service and operating expenses and to provide funds required under bond covenants. B - System of Accounts The accounting records of the Authority are maintained on an accrual basis in accordance with accounting principles generally accepted in the United States (GAAP) issued by the Governmental Accounting Standards Board (GASB) applicable to governmental entities that use proprietary fund accounting and the Financial Accounting Standards Board (FASB) that do not conflict with rules issued by the GASB. The Authority s combined financial statements include the accounts of the Lake Moultrie Regional Water System after elimination of inter-company accounts and transactions. The accounts are maintained substantially in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC) for the electric system and the National Association of Regulatory Utility Commissioners (NARUC) for the water system. The Authority also complies with policies and practices prescribed by its Board of Directors and to practices common in both industries. As the Board of Directors is authorized to set rates, the Authority has historically followed FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation (FASB 71). This statement provides for the reporting of assets and liabilities consistent with the economic effect of the rate structure. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from those estimates. C - Reclassifications Certain amounts in the prior year s financial statements have been reclassified to conform to current year presentation. D - Cash and Cash Equivalents For purposes of the Combined Statements of Cash Flows, the Authority considers highly liquid investments with original maturities of ninety days or less and cash on deposit with financial institutions as cash and cash equivalents. In 2001, the Authority adopted GASB Statement No. 34, Basic Financial Statements - Management s Discussion and Analysis - for State and Local Governments (GASB 34) which requires cash and cash equivalents to be shown as either restricted or unrestricted. Restricted refers to those funds limited by law, regulations or Board action as to their allowable disbursement. Unrestricted refers to all other funds not meeting the requirements of restricted. E - Inventory Material inventory and fuel inventory are carried at weighted average costs. At the time of issuance or consumption, an expense is recorded at the weighted average cost. Fuel inventory costs for customers other than Central Electric Power Cooperative Inc. ( Central ) are billed utilizing a fuel adjustment clause based on the weighted average costs for the previous three-month period. F - Utility Plant Utility plant is recorded at cost, which includes materials, labor, overhead, and interest capitalized during construction. Interest is only capitalized when interest payments are funded through borrowings. There was no interest capitalized in 2005 or Other interest expense is recovered currently through rates. The costs of maintenance, repairs and minor replacements are charged to appropriate operation and maintenance expense accounts. The costs of renewals and betterments are capitalized. The original cost of utility plant retired and the cost of removal, less salvage, are charged to accumulated depreciation. G - Depreciation Depreciation is computed using composite rates on a straight-line basis over the estimated useful lives of the various classes of the plant. Composite rates are applied to the net carrying basis of various classes of plant which includes appropriate adjustments for cost of removal and salvage. The Authority periodically has depreciation studies performed by independent parties to assist management and the Board in establishing appropriate composite depreciation rates. Annual depreciation provisions, expressed as a percentage of average depreciable utility plant in service, were approximately 3.6 percent and 3.5 percent for the periods ended December 31, 2005 and 2004, respectively. Amortization of capitalized leases is also included in depreciation expense. H - Investment in Associated Companies The Authority is a member of The Energy Authority (TEA) along with City Utilities of Springfield (Missouri), Gainesville Regional Utilities (Florida), JEA (Florida), the Municipal Electric Authority of Georgia (MEAG), and Nebraska Public Power District (NPPD). The Authority is also a member of Colectric Partners (Colectric). In addition to the Authority, Colectric s member participants are: JEA, MEAG, NPPD, Gainesville Regional Utilities and Florida Municipal Power Agency. TEA markets wholesale power and coordinates the operation of the generation assets of its members to maximize the efficient use of electrical energy resources, reduce operating costs and increase operating I-7

49 Appendix 1 financials revenues of the members. TEA is expected to accomplish the foregoing without impacting the safety and reliability of the electric system of each member. TEA does not engage in the construction or ownership of generation or transmission assets. In addition, TEA assists members with natural gas hedging activities and acts as an agent in the execution of forward gas transactions. The Authority accounts for its investment in TEA under the equity method of accounting. All of TEA s revenues and costs are allocated to the members. The following table summarizes the transactions applicable to the Authority. TEA Investment (Thousands) Opening balance $ 6,741 $ 9,096 Reduction to power costs and increases in electric revenues 44,952 16,860 Less: Distributions from TEA 44,164 14,463 Less: Collateral refund 0 3,362 Less: Other (Includes Equity Losses) 1,134 1,390 Ending balance $ 6,395 $ 6,741 At December 31, 2005, the Authority had a payable to TEA of $30.2 million for power and gas purchases. In addition, at December 31, 2005, the Authority had a receivable due from TEA of approximately $6.0 million for power sales and sales of excess gas capacity. The Authority s exposure relating to TEA is limited to the Authority s capital investment, any accounts receivable and trade guarantees provided by the Authority. These guarantees are within the scope of FASB Financial Interpretation No. 45, Guarantor s Accounting and Disclosure Requirements for Guarantees (FIN 45). Upon the Authority making any payments under its electric guaranty, it has certain contribution rights with the other members of TEA in order that payments made under the TEA member guaranties would be equalized ratably, based upon each member s equity ownership interest in TEA. After such contributions have been effected, the Authority would only have recourse against TEA to recover amounts paid under the guaranty. The term of this guaranty is generally indefinite, but the Authority has the ability to terminate its guaranty obligations by causing to be provided advance notice to the beneficiaries thereof. Such termination of its guaranty obligations only applies to TEA transactions not yet entered into at the time the termination takes effect. The Authority s support of TEA s trading activities is limited based on the formula derived from the forward value of TEA s trading positions at a point in time. The formula was approved by the Authority s Board of Directors and at December 31, 2005, the trade guarantees are an amount not to exceed approximately $96.0 million. Colectric provides public power utilities with key project and business management resources. Colectric also specializes in the development, project management, operations and maintenance of public power utilities electric generation and gas infrastructure facilities. The members may elect to participate in various Colectric initiatives based on individual utility needs. Currently, the Authority participates in two of Colectric s initiatives. The first involves managing the major gas turbine overhauls thereby promoting the sharing of spare parts and technical expertise. The second initiative is a joint electronic procurement program intended to achieve major equipment cost savings through collective purchasing power. The Authority s exposure relating to Colectric is limited to the Authority s capital investment in Colectric, any accounts receivable from Colectric and any indemnifications related to agreements between Colectric and the Authority. These indemnifications are within the scope of FIN 45. The Authority s initial investment in Colectric was $413,000. The balance in the Authority s Member Equity account at December 31, 2005 was approximately $172,000. I - Bond Issuance Costs and Refunding Activity Unamortized debt discount, premium, and expense are amortized to income over the terms of the related debt issues. Gains or losses on refunded debt are amortized to income over the shorter of the remaining life of the refunded debt or the life of the new debt. J - Revenue Recognition and Fuel Costs Substantially all wholesale and industrial revenues are billed and recorded at the end of each month. Revenues for electricity delivered to retail customers that have not been billed are accrued. Accrued revenue for retail customers totaled $10.1 million in 2005 and $9.3 million in Fuel costs are reflected in operating expenses as fuel is consumed. K - Payment to the State - The Authority is operated for the benefit of the people of South Carolina (the State ). By law, any and all net earnings of the Authority not necessary for prudent operations, debt service, or other obligations or agreements made with the purchasers or holders, shall be paid semiannually to the State. Historically, the Authority has paid such amounts in July and January. The Authority recognizes the distributions (shown as Transfers out on the Combined Statements of Revenues, Expenses and Changes in Net Assets) as a reduction of net assets when paid. Payments made to the State totaled $12.4 million in 2005 and $24.2 million in The 2004 amount included the non-recurring special payment of $13.0 million intended to provide financial support to the State in its 2005 fiscal operating year and were recognized as reductions in the Authority s net assets during Proceeds to fund this payment are being raised by the sale of certain land assets deemed not critical to the operations of the Authority. L - Accounting for Derivative Instruments The Authority follows the requirements of FASB No. 133, Accounting for Derivative Instruments and Hedging Activities (FASB 133) as amended by FASB No The majority of the Authority s derivative instruments have been determined to meet the normal purchases and normal sales exception provided by FASB 133. The Authority engages in gas hedging activity through TEA in an effort to reduce the overall cost of fuel inventories. Unrealized gains and losses related to such activity are deferred in a regulatory account and recognized in earnings as the gas is consumed in the production cycle. At December 31, 2005, the Authority recorded $31.8 million in net unrealized gains from natural gas hedging transactions using mark-to-market accounting as outlined by FASB 133. During 2005, the Authority incurred $17.8 million in net realized gains associated with natural gas transactions. M - Retirement of Long-Lived Assets - Statement of Financial Accounting Standards No. 143 "Accounting for Asset Retirement Obligations" (SFAS 143) addresses financial accounting and reporting for legal obligations associated with the retirement of long-lived assets and I-8

50 financials the related retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from acquisition, construction and/or normal use of the asset. The Authority has a one-third undivided interest in the V.C. Summer Nuclear Station ("Summer") and is therefore subject to the requirements of SFAS 143 due to legal and regulatory requirements related to nuclear decommissioning. Summer was placed in service in 1983 and its current operating license expires in In May 2004, the Nuclear Regulatory Commission (NRC) accepted an application for a 20-year license extension at Summer. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of a liability is added to the carrying amount of the associated asset. This carrying amount, called the Asset Retirement Cost (ARC) is then depreciated over the life of the asset. The asset retirement obligation liability increases due to the passage of time based on the time value of money until the retirement obligation is settled. SFAS 143 was effective for fiscal years beginning after June 15, 2002, and was adopted by Santee Cooper on January 1, At December 31, 2005 and 2004, the Authority recorded an asset retirement obligation (ARO) on its one-third share of Summer of approximately $273.1 million and $260.6 million respectively. Approximately $82.9 million was recorded on the accompanying balance sheet as an associated ARC within "Capital Assets." The ARC was recorded commencing on the in-service date of the nuclear facility. In March 2005, FASB issued Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations" (FIN 47). FIN 47 clarifies the accounting for conditional asset retirement obligations as used in SFAS 143. It requires that an entity recognize a liability for the fair value of a conditional asset retirement obligation when incurred if the fair value of the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional asset retirement obligation is factored into the measurement of the liability when sufficient information exists. FIN 47, together with SFAS 143, provides guidance for recording and disclosing liabilities related to future legally enforceable obligations to retire assets (ARO). As a result of the adoption of FIN 47 in 2005, Santee Cooper recorded an ARO of approximately $49.3 million at December 31, 2005 for conditional obligations related to generation properties. A part of the ARO, approximately $10.4 million, was recorded as an associated ARC within "Capital Assets." The remaining $38.9 million was recorded as accretion expense. The asset retirement obligation is adjusted each period for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows. Reconciliation of Asset Retirement Obligation Liability Years Ended December 31, (Millions) Balance as of January 1, $ $ Accretion Expense Revision in Estimated Cash Flows - (28.0) Adoption of FIN Balance as of December 31, $ $ Appendix 1 N - Adoption of New Accounting Standards - In March 2003, the GASB issued Statement No. 40, Deposit and Investment Risk Disclosures an Amendment of GASB Statement No. 3 (GASB 40). This Statement addresses common deposit and investment risks related to credit risk, concentration of credit risk, interest rate risk, and foreign currency risk. As an element of interest rate risk, this Statement requires certain disclosures of investments that have fair values that are highly sensitive to changes in interest rates. Deposit and investment policies related to the risks identified in this Statement must also be disclosed. This Statement is effective for the Authority beginning in fiscal year The implementation of this Statement does not have a material effect on the Authority s financial position or results of operations. In November 2003, GASB issued Statement No. 42, Accounting and Financial Reporting for Impairment of Capital Assets and for Insurance Recoveries (GASB 42) which is effective for the Authority s 2005 financial reporting. This Statement establishes accounting and financial reporting standards for impairment of capital assets. Adoption of GASB 42 does not have a material effect on the Authority s financial position or results of operations. In April 2004, GASB issued statements No. 43, Financial Reporting for Postemployment Benefit Plans Other than Pension Plans (GASB 43) and in June, 2004 issued No. 45, Accounting and Financial Reporting by Employers for Postemployment Benefits Other Than Pensions (GASB 45). The purpose of these two statements is to set new accounting standards for state and local government employers that offer retiree health benefits and other non-pension postemployment benefits. In particular, these statements require the accrual of liabilities and expenses of other postemployment benefits (OPEB) over the working career of plan members. The effective start date of GASB 43 applies for periods beginning after December 15, 2005 for companies with total annual revenues of $100 million or more. GASB 45 regulations come into effect one year after implementation of GASB 43. The Authority believes that it does not fall under the requirements of GASB 43 since the South Carolina Retirement System provides certain health, dental, and life insurance benefits for retired employees of the Authority. The requirements of GASB 45 are currently still under review. The implementation of GASB 43 and GASB 45 is not expected to have a material effect on the Authority s financial position or results of operations. In December 2004, FASB issued Statement No. 153, Exchanges of Nonmonetary Assets (FASB 153) which became effective for the Authority s 2005 fiscal year. FASB 153 amended APB Opinion 29 which provided guidance for accounting for nonmonetary transactions. FASB 153 eliminated the exception to fair value for exchanges of similar productive assets and replaced it with a general exception for exchange transactions that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. In accordance with FASB 153, the Authority recorded immaterial gains due to nonmonetary exchanges which were deferred under provisions of FASB 71. O - Issued But Not Yet Effective Pronouncements - In May 2004, GASB issued Statement No. 44, Economic Condition Reporting: The Statistical Section (GASB 44). GASB 44 enhances and updates the statistical section that accompanies a state or local government s basic financial statements to reflect the significant changes that have taken I-9

51 Appendix 1 financials place in government finance, including the more comprehensive government-wide financial information required by GASB Statement 34. The statistical section comprises schedules presenting trend information about revenues and expenses, outstanding debt, economics and demographics, and other subjects. These schedules are intended to provide financial statement users with contextual information they need to assess a government s financial health. GASB 44 is effective for the Authority beginning in fiscal year Implementation of this Statement is not expected to have a material effect on the Authority s financial position or results of operations. In December 2004, GASB issued Statement No. 46, Net Assets Restricted by Enabling Legislation - an amendment of GASB Statement 34 (GASB 46). This Statement clarifies that a legally enforceable enabling legislation restriction is one that a party external to a government such as citizens, public interest groups, or the judiciary can compel a government to honor. GASB 46 states that the legal enforceability of an enabling legislation restriction should be re-evaluated if any of the resources raised by the enabling legislation are used for a purpose not specified by the enabling legislation or if a government has other cause for reconsideration. The only enabling legislation affecting the Authority is that legislation (SC Code of Laws Section et seq.) by which it was created. There has been no enabling legislation since inception that imposes limits on the use of new capital. Therefore, the Authority believes it does not fall under the requirements of GASB 46. In June 2005, GASB issued Statement No. 47, Accounting for Termination Benefits (GASB 47). This statement establishes accounting standards for termination benefits. The Authority has established that general recognition and measurement requirements should be reported under the requirements of GASB Statement No. 27, Accounting for Pensions by State and Local Government Employers (GASB 27), or GASB Statement No. 45, Accounting and Financial Reporting by Employers for Post-employment Benefits other than Pensions (GASB 45) because we are a member of the South Carolina Retirement System. The Authority believes it does not fall under the requirements of GASB 47 due to following the requirements of GASB 27 and GASB 45. Note 2 Costs to Be Recovered from Future Revenue: The Authority s electric rates are established based upon debt service and operating fund requirements. Depreciation is not considered in the cost of service calculation used to design rates. In accordance with FASB 71, the differences between debt principal maturities (adjusted for the effects of premiums, discounts, expenses and amortization of deferred gains and losses) and depreciation on debt financed assets are recognized as costs to be recovered from future revenue. The recovery of outstanding amounts recorded as costs to be recovered from future revenue will coincide with the repayment of the applicable outstanding debt of the Authority. Note 3 Cash and Investments Held by Trustee: Cash and investments as of December 31, 2005 are classified in the accompanying financial statements as follows ($000 s): Combined Balance Sheet: Current assets Unrestricted cash and cash equivalents $ 79,068 Unrestricted investments 78,427 Restricted cash and cash equivalents 136,101 Restricted investments 22,323 Noncurrent assets Unrestricted cash and cash equivalents 62 Unrestricted investments 54,000 Restricted cash and cash equivalents 37,901 Restricted investments 207,014 Total cash and investments $ 614,896 Cash and investments as of December 31, 2005 consist of the following: Cash/Deposits $ 28,603 Investments 586,293 Total cash and investments $ 614,896 Unexpended funds from the sale of bonds, debt service funds, other special funds, and cash and investments are held and maintained by trustees, and their use is designated in accordance with applicable provisions of various trust indentures, bond resolutions, lease agreements, and the Enabling Act included in the South Carolina Code of Laws. The Authority s investments are authorized by the Enabling Act included in the South Carolina Code of Laws, the Authority s investment policy, and various debt resolutions. Authorized investment types include Federal Agency Securities, State of South Carolina General Obligation Bonds, and U. S. Treasury Obligations all of which are limited to a ten year maximum maturity. Certificate of Deposits and Repurchase Agreements are also authorized with a maximum maturity of one year. In 1998, the Authority adopted the provisions of GASB Statement No. 31, Accounting and Financial Reporting for Certain Investments and for External Investment Pools (GASB 31). GASB 31 establishes standards of accounting and financial reporting for certain investments in securities and requires that all equity and debt securities be recorded at their fair value with gains and losses in fair value reflected as a component of non-operating income in the Combined Statements of Revenues, Expenses and Changes in Net Assets. As of December 31, 2005 and 2004, the Authority had investments totaling approximately $586.3 million and $856.0 million, respectively. As of December 31, 2005, the Authority s cash and investments carried at fair market value included nuclear decommissioning funds of $123.1 million including unrealized holding gains of $12.6 million. As of December 31, 2004, decommissioning funds totaled approximately $116.4 million including unrealized holding gains of $14.2 million. In accordance with the provisions of FASB 71, earnings, both realized and unrealized, on the decommissioning fund assets are credited to the Regulatory asset - asset retirement obligation and not as a separate component of non-operating income in the Combined Statements of Revenues, Expenses and Changes in Net Assets. All of the Authority s investments, with the exception of decommissioning funds, are limited to a maturity of 10 years or less. For the year ended December 31, 2005, the Authority made total investment purchases and I-1 0

52 financials sales at cost of approximately $30.4 billion and $30.6 billion, respectively. Of these amounts, the Authority s investment purchases and sales at cost for its decommissioning funds were $49.9 million and $46.7 million, respectively. Compared to the year ended December 31, 2004, the Authority s total investment purchases and sales at cost were approximately $38.7 billion and $38.6 billion, respectively. Of these amounts, investment purchases and sales at cost for the decommissioning funds were $45.2 million and $36.4 million, respectively. With adoption of GASB Statement No. 40, Deposit and Investment Risk Disclosures (GASB 40), reporting requirements for GASB Statement No. 3, Deposits with Financial Institutions, Investments (including Repurchase Agreements), and Reverse Repurchase Agreements (GASB 3) were modified. Under disclosure requirements for GASB 3, the Authority s repurchase agreements at December 31, 2005 totaled approximately $165.0 million. The Authority requires that securities underlying repurchase agreements have a market value of at least 102 percent of the cost of the repurchase agreement. Securities underlying repurchase agreements are delivered by broker/dealers to the Authority s trust agents. Prior disclosure requirements concerning credit and market risk are now included in GASB 40 disclosures. GASB 40 addresses modifications of disclosure requirements for common deposit and investment risks related to credit risk, custodial credit risk, concentration of credit risk, interest rate risk, and foreign currency risk. The Authority s requirements for disclosure are as follows. Credit Risk - Generally, credit risk is the risk that an issuer of an investment will not fulfill its obligation to the holder of the investments. This is measured by the assignment of rating by a nationally recognized statistical rating organization. State law and restrictions established by bond indenture and resolution limit investments in debt securities to those securities issued by the U.S government and agencies or instrumentality of the United States created pursuant to an Act of Congress. Examples of these agencies securities are Federal Home Loan Bank and Federal National Mortgage Association. As of December 31, 2005, all of the agencies securities held by the Authority were rated AAA by Fitch and Aaa by Moody s Investors Services. Custodial Credit Risk - Custodial credit risk for deposits is the risk that, in the event of the failure of a depository financial institution, an entity will not be able to recover its deposits or will not be able to recover collateral securities that are in the possession of an outside party. The custodial credit risk for investments is the risk that, in the event of the failure of the counterparty to a transaction, an entity will not be able to recover the value of its investment or collateral securities that are in the possession of another party. As of December 31, 2005, all of the Authority s investment securities are held by the Trustee or Agent of the Authority and therefore have no custodial risk. At December 31, 2005, the Authority had deposits exposed to custodial credit risk as follows ($000 s): Depository Account Type Bank Balance Uninsured and collateral held by Bank s agent not in Authority s name $ 3,842 Uninsured and uncollateralized 317 Total $ 4,159 Appendix 1 Concentration of Credit Risk -The investment policy of the Authority contains no limitations on the amount that can be invested in any one issuer. Investments in any one issuer (other than U.S. Treasury securities) that represent 5 percent or more of total Authority investments are as follows ($000 s): Issuer Investment Type Fair Value Federal Home Loan Bank Federal agency securities $ 78,856 Federal National Mortgage Association Federal agency securities $ 100,790 Interest Rate Risk - Interest rate risk is the risk that changes in market interest rates will adversely affect the fair value of an investment. Generally, the longer the maturity of an investment, the greater the sensitivity of its fair value to changes in market interest rates. The Authority manages its exposure to interest rate risk by investing in securities that mature as necessary to provide the cash flow and liquidity needed for operations. The following table shows the distribution of the Authority s investments by maturity: Weighted Average Fair Value Maturity Investment Type ($000 s) (Years) Certificates of Deposits $ 2, Federal Agency Discount Notes 89, Federal Agency Securities 150, Repurchase Agreements 165, U.S. Treasury Bills 19, U.S. Treasury Obligations 159, Total $ 586,293 Portfolio Weighted Average Maturity 2.07 The Authority holds zero coupon bonds which are highly sensitive to interest rate fluctuations in both the Nuclear Decommissioning Trust and Nuclear Decommissioning Fund. Together these accounts hold $55,550,000 in U. S. Treasury Strips ranging in maturity from 2/15/06 to 5/15/19. They also hold $61,738,000 in government agency securities (i.e. Resolution Corp, FNMA, FICO and REFCORP Securities) in the two portfolios ranging in maturity from 1/15/06 to 11/15/26. Zero coupon bonds or US Treasury Strips are subject to wider swings in their market value than coupon bonds. These portfolios are structured to hold these securities to maturity or early redemption. The Authority has a buy and hold strategy for these portfolios. The decommissioning date of the nuclear station is It is anticipated that no funds will be needed any earlier than 2043 and may not be needed for another 50 years beyond that date. The Authority has no other investments that are highly sensitive to interest rate fluctuations. Foreign Currency Risk - Foreign currency risk exists when there is a possibility that changes in exchange rates could adversely affect in investment or deposit fair market value. The Authority is not authorized to invest in foreign currency and therefore has no exposure. I-11

53 Appendix 1 financials Note 4 - Long-Term Debt Outstanding: The Authority's long-term debt at December 31, 2005 and 2004 consisted of the following: Interest Call Rate(s) (1) Price (1) (Thousands) Electric Revenue Bonds - Priority Obligations: (mature through 2006) $ 4,420 $ 8, % 100 Capitalized Lease Obligations (Net): (mature through 2014) 11,937 14, N/A Revenue Bonds: (mature through 2032) 1993 Tax-exempt Refunding Series C 0 86,335 N/A N/A 1995 Tax-exempt Refunding Series A 0 77,560 N/A N/A 1995 Tax-exempt Refunding Series B 0 148,825 N/A N/A 1996 Tax-exempt Refunding Series A 0 217,030 N/A N/A 1996 Tax-exempt Refunding Series B 0 21,505 N/A N/A 1997 Tax-exempt Refunding Series A 204, , Tax-exempt Refunding Series B 23,200 23, Total Revenue Bonds 228, ,050 Revenue Obligations: (mature through 2039) 1999 Tax-exempt Improvement Series A 181, , Taxable Improvement Series B 68,135 72, Non-callable 2001 Tax-exempt Improvement Series A 44,265 46, Tax-exempt Refunding Series A 3,100 3, Non-callable 2002 Tax-exempt Refunding Series A 104, , Tax-exempt Improvement Series B 281, , Taxable Improvement Series C 68,765 91, P&I Plus Make- Whole Premium 2002 Tax-exempt Refunding Series D 418, , Tax-exempt Refunding Series A 335, , Tax-exempt Improvement Series A 434, , Taxable Improvement Series B 17,635 17, P&I Plus Make- Whole Premium 2004 Tax-exempt Improvement Series M - CIBS 19,756 19, Tax-exempt Improvement Series M - CABS 8,557 8, Accreted Value 2005 Tax-exempt Refunding Series A 125, Tax-exempt Refunding Series B 278, Tax-exempt Refunding Series C 78, Tax-exempt Improvement Series M - CIBS 10, Tax-exempt Improvement Series M - CABS 4, Accreted Value Total Revenue Obligations 2,482,392 2,039,815 Less: Current Portion - Long-term Debt 69,674 80,994 Total Long-term Debt - (Net of current portion) $ 2,657,160 $ 2,764,450 (1) Apply only to bonds outstanding as of 12/31/2005. I-12

54 financials Appendix 1 Maturities of long-term debt are as follows: Priority Capitalized Revenue Revenue Total Total Obligations Leases Bonds Obligations Principal Interest Total Year Ending December 31, (Thousands) 2006 $ 4,420 $ 2,673 $ 715 $ 59,700 $ 67,508 $ 132,017 $ 199, , ,510 73, , , , ,075 87, , , , ,675 81, , , ,685 3,370 89,900 94, , , ,915 75, , , ,402 1,073, , , , ,458 1,118, , , , , , , , , , , , , ,070 52, , , ,940 6, ,466 Less: Capital Lease Cushion of Credit Account 0 (4,020) 0 0 (4,020) 0 (4,020) Total $ 4,420 $ 11,937 $ 228,085 $ 2,482,392 $ 2,726,834 $ 1,853,712 $ 4,580,546 Refunded and defeased bonds outstanding, original loss on refunding, and the unamortized loss at December 31, 2005 are as follows: Refunded and Refunding Refunded Defeased Bonds Original Unamortized Issue Bonds Outstanding Loss Loss (Thousands) Cash Defeasance $ 20,000 of the 1982 Series A $ 0 $ 2,763 $ 1,216 Cash Defeasance $ 14,080 of the 1992 Refunding Series A 14,955 of the 1996 Refunding Series A 12,345 4, Refunding Series A $ 100,000 of the 1978 Series A 68,325 of the 1991 Refunding & Improvement Series B 37,495 of the 1991 Series D 0 16,990 11,205 Commercial Paper $ 76,050 of the 1973 Series 105,605 of the 1977 series 81,420 of the 1978 Series 0 2, Refunding Series B $ 25,000 of the 1992 B Series 0 1,970 1, Refunding Series A $ 10,000 of the 1991 Refunding & Improvement Series B Refunding Series A $ 113,380 of the 1992 Refunding Series A 0 23,378 15, Refunding Series D $ 293,250 of the 1993 Refunding series A 25,900 of the 1993 Refunding Series B-1 25,900 of the 1993 Refunding Series B-2 132,095 of the 1993 Refunding Series C 0 73,613 52, Refunding Series A $ 336,385 of the 1993 Refunding Series C 15,750 of the 1995 Refunding Series A 0 57,064 49, Refunding Series A $ 74,970 of the 1995 Refunding Series A 37,740 of the 1995 Refunding Series B 20,080 of the 1996 Refunding Series A 132,790 23,864 23, Refunding Series B $ 2,590 of the 1995 Refunding Series A 100,320 of the 1995 Refunding Series B 192,305 of the 1996 Refunding Series A 21,505 of the 1996 Refunding Series B 316,720 73,749 72, Refunding Series C $ 86,335 of the 1993 Refunding Series C 0 12,125 11,577 Total $ 461,855 $ 292,680 $ 239,310 I-13

55 Appendix 1 financials The fair value of the Authority s debt is estimated based on quoted market prices for the same or similar issues or on the current rates offered to the Authority for debt with the same remaining maturities. Based on the borrowing rates currently available to the Authority for debt with similar terms and average maturities, the fair value of debt is approximately $3.1 billion and $3.2 billion at December 31, 2005 and 2004, respectively. On August 26, 2004, the Authority s Board of Directors authorized a Forward Bond Purchase Agreement for the sale of approximately $125.3 million Revenue Obligations, 2005 Refunding Series A (2005A Bonds) which were delivered on October 4, This refunding will reduce the Authority s total debt service over the life of its bonds by approximately $20.1 million, resulting in an economic gain of approximately $11.6 million. The debt was issued at an all-in true interest cost of 4.82 percent. Yields ranged from 4.23 percent in 2014 to 4.83 percent on the 2022 maturity. On January 28, 2005, the Authority s Board of Directors authorized a Forward Bond Purchase Agreement for the sale of approximately $278.0 million Revenue Obligations, 2005 Refunding Series B (2005B Bonds) which were delivered on October 4, This refunding will reduce the Authority s total debt service over the life of its bonds by approximately $58.3 million, resulting in an economic gain of approximately $29.6 million. The debt was issued at an all-in true interest cost of 4.42 percent. Yields ranged from 2.95 percent in 2008 to 4.33 percent on the 2023 maturity. On February 10, 2005, the Authority s Board of Directors authorized the sale of approximately $78.2 million Revenue Obligations, 2005 Refunding Series C (2005C Bonds). This refunding reduced the Authority s total debt service over the life of its bonds by approximately $14.6 million, resulting in an economic gain of approximately $6.0 million. The debt was issued at an all-in true interest cost of 4.41 percent. Yields ranged from 4.02 percent in 2023 to 4.20 percent on the 2025 maturity. On October 28, 2005, the Authority s Board of Directors authorized the sale of approximately $15.4 million Revenue Obligations, 2005 Series M (2005M Bonds). The 2005M Bonds consisted of Current Interest Bearing Bonds issued in denominations of $500 and Capital Appreciation Bonds issued in denominations of $200. The 2005M Bonds were issued directly by the Authority to residents of the State, customers of the Authority, members of electric cooperatives organized under the laws of the State, and electric customers of the City of Bamberg and City of Georgetown. Interest rates ranged from 3.65 percent in 2012 to 4.35 percent on the 2023 maturity. On January 13, 2006, the Authority's Board of Directors authorized the sale of approximately $599.9 million Revenue Obligations, 2006 Series A & B (2006 A & B Bonds). The 2006 Tax-Exempt Series A (2006A Bonds) totaled approximately $470.8 million. The 2006 Taxable Series B (2006B Bonds) totaled approximately $129.1 million. The 2006B Bonds were issued as taxable bonds to comply with IRS Private Use Regulations. The 2006 A & B Bonds were issued February 1, 2006 at an all-in true interest cost of 4.64% (aggregate true interest cost). The 2006 A & B Bonds will mature between January 1, 2007 and January 1, All Authority debt is secured by a lien upon and pledge of the Authority s revenues. The Authority s bond indentures provide for certain restrictions, the most significant of which are: 1. The Authority covenants to establish rates sufficient to pay all debt service, required lease payments, capital improvement fund requirements, and all costs of operation and maintenance of the Authority s electric system and all necessary repairs, replacements, and renewals thereof. 2. The Authority is restricted from issuing additional parity bonds unless certain conditions are met. As of December 31, 2005, the Authority is in compliance with all debt covenants. Note 5 - Commercial Paper: The Board of Directors has authorized the issuance of commercial paper not to exceed $500 million. The paper is issued for valid corporate purposes with a term not to exceed 270 days. For the years ended December 31, 2005 and 2004, the information related to commercial paper was as follows: Effective interest rate (at December 31) 3.22% 1.80% Average annual amount outstanding (000 s) $ 230,471 $ 250,809 Average maturity 50 days 51 days Average annual effective interest rate 2.64% 1.20% At December 31, 2005 the Authority had a Revolving Credit Agreement with Dexia Crédit Local and BNP Paribas for $450 million. This agreement is used to support the Authority s issuance of commercial paper. There were no borrowings under the agreement during 2005 or Commercial Paper outstanding at December 31, was as follows: (Thousands) Commercial Paper-Gross $ 285,617 $ 193,319 Less: Unamortized Discount on Taxable Commercial Paper Commercial Paper-Net $ 285,449 $ 193,317 Note 6 Summer Nuclear Station: The Authority and South Carolina Electric and Gas (SCE&G) are parties to a joint ownership agreement providing that the Authority and SCE&G shall own the Summer Nuclear Station with undivided interests of 33 1/3 percent and 66 2/3 percent, respectively. SCE&G is solely responsible for the design, construction, budgeting, management, operation, maintenance, and decommissioning of the Summer Nuclear Station, and the Authority is obligated to pay its ownership share of all costs relating thereto. The Authority receives 33 1/3 percent of the net electricity generated. At December 31, 2005 and 2004, the plant accounts before depreciation included approximately $488.1 million and $487.0 million, respectively, representing the Authority s investment, including capitalized interest, in the Summer Nuclear Station. The accumulated depreciation at December 31, 2005 and 2004 was $258.6 million and $245.7 million, respectively. For the years ended December 31, 2005 and 2004, the Authority s operation and maintenance expenses included $52.6 million and $54.9 million, respectively, for the Summer Nuclear Station. Nuclear fuel costs are being amortized based on energy expended, which includes a component for estimated disposal costs of spent nuclear fuel which represents the unit-of-production method. This amortization is included in fuel expense and is recovered through the Authority s rates. In 2002, SCE&G commenced a re-racking project of the on-site spent fuel pool. The new pool storage capability will permit full core off-load I-14

56 financials through Further on-site storage, if required, will be accomplished through dry cask storage or other technology as it becomes available. The Nuclear Regulatory Commission (NRC) requires a licensee of a nuclear reactor to provide minimum financial assurance of its ability to decommission its nuclear facilities. In compliance with the applicable NRC regulations, the Authority established an external trust fund and began making deposits into this fund in September In addition to providing for the minimum requirements imposed by the NRC, the Authority makes deposits into an internal fund in the amount necessary to fund the difference between a site-specific decommissioning study completed in 2000 and the NRC s imposed minimum requirement. Based on these estimates, the Authority s one-third share of the estimated decommissioning costs of the Summer Nuclear Station equals approximately $143.4 million in 1999 dollars. Each month, the Authority debits to FERC account Maintenance of Nuclear Plant, an amount equal to the deposits made to the internal and external trust funds. These costs are being recovered through the Authority s rates. Based on current decommissioning cost estimates developed by SCE&G, these funds, which totaled approximately $123.1 million (adjusted to market) at December 31, 2005, along with future deposits into both the external and internal decommissioning accounts and investment earnings, are estimated to provide sufficient funds for the Authority s one-third share of the total decommissioning costs. In 2004, the NRC granted a twenty-year extension to Summer Nuclear Station s operating license, extending it to August 6, The Energy Policy Act of 1992 gave the Department of Energy (DOE) the authority to assess utilities for the decommissioning of its facilities used for the enrichment of uranium included in nuclear fuel costs. In order to decommission these facilities, the DOE estimated that it would need to charge utilities a total of $150 million, indexed for inflation, annually for 15 years based on enrichment services used by utilities in past periods. Based on an estimate from SCE&G covering the 15 years, the Authority s remaining one-third share of the liability at December 31, 2005 totals approximately $308,000. Such amount has been deferred and will be recovered through rates as paid. These costs are included on the accompanying balance sheets in Deferred debits and other noncurrent assets - Other and Other deferred credits and noncurrent liabilities. Appendix 1 Note 7 Leases: The Authority has capital lease contracts with Central Electric Power Cooperative, Inc. (Central), covering a steam electric generating plant, transmission facilities, and various other facilities. The remaining lease terms range from 1 to 9 years. Quarterly lease payments are based on a sum equal to the interest on and principal of Central s indebtedness to the Rural Utilities Service (formerly Rural Electrification Administration) for funds borrowed to construct the above mentioned facilities. The Authority has options to purchase the leased properties at any time during the period of the lease agreements for sums equal to Central s indebtedness remaining outstanding on the properties at the time the options are exercised or to return the properties at the termination of the lease. The Authority plans to exercise each and every option to acquire ownership of such facilities prior to expiration of the leases. In addition, during 2004, the Authority became a joint participant with Central in the Rural Utilities Service (RUS) cushion of credit payments programs (COC). This program allows the borrower to build up a cushion of money for future application toward their debt while earning 5 percent interest. At December 31, 2005, the balance in the Authority s portion of the joint account was approximately $4.0 million. Future minimum lease payments on Central leases at December 31, 2005 were as follows: Amount Year ending December 31, (Thousands) 2006 $ 3, , , , , ,228 Total minimum lease payments $18,660 Less amounts representing interest 2,703 Principal Balance $15,957 Less: Cushion of Credit Account 4,020 Net Balance at December 31, 2005 $ 11,937 Property under capital leases and related accumulated amortization included in utility plant at December 31, 2005, totaled approximately $89.6 million and $79.5 million, respectively, and at December 31, 2004, totaled $90.1 million and $77.3 million, respectively. Operating lease payments totaled approximately $6.5 million and $5.8 million during the years ended December 31, 2005 and 2004, respectively. Included in these operating lease payments are periodic expenses related to leased coal cars, which are initially reflected in fuel inventory and subsequently reported in fuel expense based on the tons burned. The terms of the current coal car leases vary from twelve months to thirty-eight months, with the longest lease expiring in The approximate amounts for the coal car leases to be paid for the years 2006 through 2009 are $5.9 million, $4.9 million, $4.9 million, and $296,000, respectively. Note 8 Contracts with Electric Power Cooperatives: Power supply and transmission services are provided to Central in accordance with a power system coordination and integration agreement (the Coordination Agreement ). In addition, the Authority is the sole supplier of energy needs for Central and its member Saluda River Electric Cooperative, Inc. (Saluda) excluding energy Central receives from the Southeastern Power Administration (SEPA) and Saluda s ownership interest in the Catawba Nuclear Station. Central, under the terms of the contract with the Authority, has the right to audit costs billed to them under the cost of service contract. Differences as a result of this process are accrued if they are probable and estimable under FASB Statement No. 5, Accounting for Contingencies (FASB 5). To the extent that differences arise due to this process, prospective adjustments are made to cost of service and are reflected in operating revenues in the accompanying Combined Statements of Revenues, Expenses and Changes in Net Assets. Such adjustments in 2005 and 2004 were not material to the Authority s overall operating revenue. Note 9 Commitments and Contingencies: Budget - The Authority s capital budget provides for expenditures of approximately $558.6 million during the year ending December 31, 2006 and $ million during the two years thereafter. These expenditures I-15

57 Appendix 1 financials include $724.1 million for new generating units being constructed to begin operation in 2007 and 2009, and $156.7 million for environmental compliance expenditures. The total project cost of the new generating unit to begin operation in 2007 is $675.0 million and $755.0 million for the unit in Capital expenditures will be financed by internally generated funds and a combination of taxable and tax-exempt debt. Purchase Commitments The Authority has contracted for long-term coal purchases under contracts with estimated outstanding minimum obligations after December 31, The disclosure of minimum obligations below is based on the Authority s contract rates and represents management s best estimate of future expenditures under long-term arrangements. Amount Year ending December 31, (Thousands) 2006 $ 357, , , , , ,784 Total $ 936,231 The Authority has outstanding minimum obligations under two existing long-term and two existing short-term purchased power contracts as of December 31, The long-term obligations were approximately $75.5 million with a remaining term of 29 years and $5.2 million with a remaining term of one year. The short-term contracts totaled $1.3 million with a remaining term of five months. CSX Transportation, Inc. (CSX) provides substantially all rail transportation service for the Authority s coal-fired generating units. During 2002, a new agreement was signed with an effective date of January 1, This contract will continue to apply a price per ton of coal moved, with the minimum being set at four million tons per year. The Authority has commitments for nuclear fuel enrichment and fabrication contracts which are contingent upon the operating requirements of the nuclear unit. As of December 31, 2005, these commitments total approximately $39.3 million over the next six years. In 2003, the Authority amended the Rainey Generating Station Long- Term Service Agreement (LTSA) with General Electric International, Inc. in the approximate amount of $90.0 million. The agreement provides a contract performance manager (CPM), initial spare parts, parts and services for specified planned maintenance outages, remote monitoring and diagnostics of the turbine generators, and combustion tuning for the gas turbines. In exchange for reduced pricing and added features, the contract term was extended to 2025, but can be terminated for convenience in The previous agreement was in the approximate amount of $76.0 million and was effective through The Authority s Board of Directors has approved recovery of the LTSA on a straight-line basis over the term of the agreement. On January 31, 2005, the Authority entered a $4.0 million Parts and Services Agreement with General Electric International, Inc. (GEII) for maintenance of the Rainey 3, 4, and 5 gas turbines. GEII will supply parts, repair services, and technical direction for one combustion inspection and one hot gas path inspection for each of the three gas turbines. The term of the agreement, which is dependent upon unit operation, is expected to be nine years. Effective November 1, 2000, the Authority contracted with Transcontinental Gas Pipeline Corporation (TRANSCO) to supply gas transportation needs for its Rainey Generating Station. This is a firm transportation contract covering a maximum of 80,000 decatherms per day for 15 years. Risk Management The Authority is exposed to various risks of loss related to torts; theft of, damage to, and destruction of assets; business interruption; and errors and omissions. The Authority purchases commercial insurance to cover these risks, subject to coverage limits and various exclusions. Settled claims resulting from these risks have not exceeded commercial insurance coverage in any of the past three years. Policies are subject to deductibles ranging from $5,000 to $1.0 million, with the exception of named storm losses which carry deductibles from $1.0 million up to $5.0 million. Also a $1.4 million general liability self-insured layer exists between the Authority s primary and excess liability policies. During 2005, there were no losses incurred or reserves recorded for general liability. On August 5, 2005, a generator stator failure occurred at the Cross Generating Station resulting in an extended outage and leading the Authority to file a claim with its property insurance carrier for approximately $4.3 million. The final settlement was approximately $3.9 million subject to the Authority s $1.0 million deductible. The Authority received payment of this claim during The Authority is self-insured for auto, dental, worker s compensation and environmental incidents that do not arise out of an insured event. The Authority purchases commercial insurance, subject to coverage limits and various exclusions, to cover automotive exposure in excess of $2.0 million per incident. Risk exposure for the dental plan is limited by plan provisions. There have been no third-party claims for environmental damages for 2005 or Claims expenditures and liabilities are reported when it is probable that a loss has occurred and the amount of the loss can be reasonably estimated. At December 31, 2005, the amount of the self-insured liabilities for auto, dental, worker s compensation and environmental remediation was approximately $2.6 million. The liability is the Authority s best estimate based on available information. Changes in the reported liability are as follows: (Thousands) Unpaid claims and claim expenses at beginning of year $ 2,375 $ 2,228 Incurred claims and claim adjustment expenses: Provision for insured events of the current year 1,724 2,282 Payments for current and prior years 1,502 2,135 Total unpaid claims and claim expenses at end of year $ 2,597 $ 2,375 The Authority pays insurance premiums to certain other State agencies to cover risks that may occur in normal operations. The insurers promise to pay I-16

58 financials to, or on behalf of, the insured for covered economic losses sustained during the policy period in accordance with insurance policy and benefit program limits. Several State funds accumulate assets, and the State itself assumes all risks for the following: Claims of covered employees for health benefits (Employee Insurance Program); not applicable for worker s compensation injuries, and Claims of covered employees for basic long-term disability and group life insurance benefits (Retirement System). Employees elect health coverage through either a health maintenance organization or through the State s self-insured plan. All other coverages listed above are through the applicable State self-insured plan except that additional group life and long-term disability premiums are remitted to commercial carriers. The Authority assumes the risk for claims of employees for unemployment compensation benefits and pays claims through the State s self-insured plan. Nuclear Insurance The maximum liability for public claims arising from any nuclear incident has been established at $10.9 billion by the Price- Anderson Indemnification Act. This $10.9 billion would be covered by nuclear liability insurance of about $300.0 million per site, with potential retrospective assessments of up to $100.6 million per licensee for each nuclear incident occurring at any reactor in the United States (payable at a rate not to exceed $15.0 million per incident, per year). Based on its onethird interest in Summer Nuclear Station, the Authority could be responsible for the maximum assessment of $33.5 million, not to exceed approximately $5 million per incident, per year. This amount is subject to further increases to reflect the effect of (i) inflation, (ii) the licensing for operation of additional nuclear reactors, and (iii) any increase in the amount of commercial liability insurance required to be maintained by the NRC. Additionally, SCE&G and the Authority maintain, with Nuclear Electric Insurance Limited (NEIL), $500.0 million primary and $1.5 billion excess property and decontamination insurance to cover the costs of cleanup of the facility in the event of an accident. In addition to the premiums paid on the primary and excess policies, SCE&G and the Authority could also be assessed a retrospective premium, not to exceed 10 times the annual premium of each policy, in the event of property damage to any nuclear generating facility covered by NEIL. Based on current annual premiums and the Authority s one-third interest, the Authority s maximum retrospective premium would be $2.5 million for the primary policy and $3.2 million for the excess policy. SCE&G and the Authority also maintain accidental outage insurance to cover replacement power costs (within policy limits) associated with an insured property loss. This policy also carries a potential retrospective assessment of $1.5 million. The Authority is self-insured for any retrospective premium assessments, claims in excess of stated coverage, or cost increases due to the purchase of replacement power associated with an uninsured event. Management does not expect any retrospective assessments, claims in excess of stated coverage, or cost increases for any periods through December 31, Clean Air Act The Authority endeavors to ensure that its facilities comply with applicable environmental regulations and standards. In addition to the existing Clean Air Act (CAA) Federal Acid Rain (SO 2 ) and the State NOx Implementation Plan (SIP) Call Programs, the EPA recently promulgated two Clean Air Regulations: Clean Air Interstate Rule (CAIR), and Clean Air Mercury Rule (CAMR). Both CAIR and CAMR were effective in July Together, they address further reductions in SO2, NOx, and Hg. Appendix 1 The Authority, along with other utilities, has challenged the SO2 allocation portion of CAIR, and is participating in a stakeholders process to develop with South Carolina Department of Health and Environmental Control (DHEC) a SIP for CAIR and CAMR in South Carolina. The Authority has been operating under a recent settlement agreement, called the Consent Decree, that became effective June 24, The settlement with the Environmental Protection Agency (EPA) and DHEC was related to certain environmental issues associated with coal-fired units. It involved the payment of a civil penalty, an agreement to perform certain environmentally beneficial projects, and the expenditure of capital costs of approximately $205.3 million to achieve emissions reductions over the period ending These capital costs are expected to be largely offset by savings resulting from a reduced need to purchase emission credits. Safe Drinking Water Act The Authority continues to monitor for Safe Drinking Water Act regulatory issues impacting electrical utilities. DHEC has primacy for regulatory authority of potable water systems in South Carolina. The State Primary Drinking Water Regulation, R.61-58, governs the design, construction, and operational management of all potable water systems in South Carolina subject to and consistent with the requirements of the Safe Drinking Water Act and the implementation of federal drinking water regulations. The Authority endeavors to manage its potable water systems for compliance with R Clean Water Act The Authority continues to monitor for Clean Water Act (CWA) regulatory issues impacting electrical utilities. The Authority completed updates to its Spill Prevention, Control, and Countermeasure (SPCC) program in response to recent changes to the federal SPCC regulations. The Authority also responded to recent federal regulatory changes requirements that cooling water intake structures reflect best technology available for minimizing adverse environmental impact (Section 316b of the CWA). The Authority has two generating stations subject to the new federal Phase II 316b Rule and has initiated activities to achieve compliance with the rule. Additionally, plans to construct a new intake structure at a Cross Station for new unit construction triggered Phase II 316(b) Rule requirements, therefore the Authority has initiated activity to achieve compliance. Open Access Transmission Tariff - On April 24, 1996, the FERC issued Orders 888 and 889: the implementing rules for mandatory non-discriminatory open access over the transmission systems of jurisdictional entities. Order 888 required each jurisdictional transmission owner to file with FERC by July 9, 1996 a pro forma open access transmission tariff (OATT). Order 888 also requires that a non-jurisdictional utility, such as the Authority, must agree to provide comparable transmission service over its transmission facilities in order to receive service from a jurisdictional utility under its OATT. In order to ensure it would be able to receive transmission service from jurisdictional utilities, in 1997 the Authority adopted an open access transmission tariff substantially in conformance with the tariff required to be filed by jurisdictional utilities. Finally, in late 2005, FERC opened a rulemaking docket to consider possible reforms to Order 888. Among the many issues that FERC will consider at this docket is whether Order 888 should be revised in light of new Section 211A of the Federal Power Act, Open Access by Unregulated Transmitting Utilities. Under new Section 211A, FERC has I-17

59 Appendix 1 financials authority to require an otherwise non-jurisdictional transmission owner, such as the Authority, owning or operating transmission facilities to provide transmission services at (1) rates that are comparable to those they charge themselves, and (2) terms and conditions that are comparable to those they charge themselves and that are not unduly discriminatory or preferential. Regional Transmission Organizations (RTOs) - Presently there are no active RTO development activities in the southeastern United States. Two previous efforts to develop an RTO for the southeastern United States have resulted in failure. In each case, the effort failed because of the lack of demonstrable benefits from forming an RTO and the lack of consensus support and acceptance from all applicable state and federal agencies for the proposed RTO structure. Whether a new RTO development effort will arise in the southeastern United States is unknown at this time. Any potential impact on the Authority of such a new effort is likewise unknown. Energy Policy Act of On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005 (EPACT 2005). EPACT 2005 is the first comprehensive energy legislation enacted by Congress since the Energy Policy Act of 1992 ("EPACT 1992"). However, unlike EPACT 1992, EPACT 2005 does not represent a fundamental change from the immediate past. EPACT 2005 includes several provisions intended to promote the use of nuclear power, including the extension of the Price-Anderson Act for 20 years (until 2025), as well as on a limited basis, provisions intended to encourage the construction of advanced nuclear facilities including possible loan guarantees, standby support and production tax credits. EPACT 2005 introduces a new Section 211A of the Federal Power Act ("FPA"), "Open Access by Unregulated Transmitting Utilities." Under Section 211A, FERC has authority to require an otherwise non-jurisdictional transmission owner owning or operating transmission facilities, such as Santee Cooper, to provide transmission services at (1) rates that are comparable to those they charge themselves, and (2) terms and conditions that are comparable to those they charge themselves and that are not unduly discriminatory or preferential. EPACT 2005 also introduces a new Section 217 of the FPA, "Native Load Service Obligation." Under this provision, any load-serving entity with a service obligation, including an otherwise non-jurisdictional transmission owner, is entitled to use its transmission capacity to meet its native load service obligation in preference to other uses of the grid. EPACT 2005 introduces a new Section 215 of the FPA which authorizes the FERC to designate an Electric Reliability Organization ("ERO") that would propose reliability standards that would be reviewed by FERC before becoming final. The Authority is currently evaluating this new Act and the full impact on the Authority is unknown. Legal Matters The Authority is a party in various claims and lawsuits that arise in the conduct of its business. Although the results of litigation cannot be predicted with certainty, in the opinion of management and Authority counsel, the ultimate disposition of these matters will not have material adverse effect on the financial position or results of operations of the Authority, except as described below. Certain plaintiffs who are customers of members of Central have filed suit against the Authority and members of Central seeking monetary damages arising out of a change in the Good Cents rate. The plaintiffs seek to represent a class of all Good Cents customers of Central s members. The Authority has answered the complaint by denying the material allegations and opposing the request for class certification. The parties have reached a tentative settlement, which has not yet been approved by the court. Until the settlement agreement has been approved, no accurate prediction of the outcome or estimate of range of loss is possible. Landowners located along the Santee River contend that the Authority is liable for damage to their real estate as a result of flooding that has occurred since the U.S. Army Corps of Engineers Cooper River Rediversion Project was completed in A jury trial held in 1997 in the U.S. District Court, Charleston, SC, returned a verdict against the Authority on certain causes of action. The Authority appealed the decision to the Fourth Circuit Court of Appeals which, after oral arguments, remanded the case to the District Court. No estimate relative to potential loss to the Authority can be made at this time. The U.S. Army Contract Board of Appeals has determined that the contract between the Corps and the Authority requires that the Corps indemnify the Authority for certain claims arising out of the construction and operation of the project. Note 10 Retirement Plan: Substantially all Authority regular employees must participate in one of the components of the South Carolina Retirement System (System), a cost sharing, multiple-employer public employee retirement system, which was established by Section of the South Carolina Code of Laws. The payroll for active employees covered by the System for each of the years ended December 31, 2005 and 2004 was approximately $96.0 million and $89.5 million, respectively. Vested employees who retire at age 65 or with 28 years of service at any age are entitled to a retirement benefit, payable monthly for life. The annual benefit amount is equal to 1.82 percent of their average final compensation times years of service. Benefits fully vest on reaching five years of service. Reduced retirement benefits are payable as early as age 55 with 25 years of service. The System also provides death and disability benefits. Benefits are established by State statute. Effective January 1, 2001, Section of the South Carolina Code of Laws allowed employees eligible for service retirement to participate in the Teacher and Employee Retention Incentive (TERI) Program. TERI participants may retire and begin accumulating retirement benefits on a deferred basis without terminating employment for up to five years. Upon termination of employment or at the end of the TERI period, whichever is earlier, participants will begin receiving monthly service retirement benefits which include any cost of living adjustments granted during the TERI period. Because participants are considered retired during the TERI period, they do not earn service credit or disability retirement benefits. TERI employees began re-contributing to the System at 6.25 percent effective July 1, However, no service credit is earned under the new regulations. The group life insurance of one times annual salary was re-established for TERI participants. Each participant is entitled to be paid for up to 45 days of accumulated unused annual vacation leave upon retirement and again at the end of the program period for any annual vacation leave earned during the program period. Article X, Section 16 of the South Carolina Constitution requires that all State-operated retirement plans be funded on a sound actuarial basis. Title 9 of the South Carolina Code of Laws (as amended) pre- I-18

60 financials scribes requirements relating to membership, benefits, and employee/employer contributions. Employees are required by State statute to contribute 6.25 percent of salary to the System. The Authority is required by the same statute to contribute 7.55 percent of total payroll for retirement and an additional 0.15 percent for group life. The contribution requirement for the years ended December 31, 2005 and 2004 was approximately $7.7 million and $7.5 million, respectively, from the Authority and $5.9 million and $5.4 million, respectively from employees. The Authority made 100 percent of the required contributions for each of the years ended December 31, 2005 and The System issues a stand alone financial report that includes all required supplementary information. The report may be obtained by writing to: South Carolina Retirement System, P.O. Box 11960, Columbia, S.C Effective July 1, 2002, new employees have a choice of type of retirement plan in which to enroll. The State Optional Retirement Plan (State ORP) which is a defined contribution plan is an alternative to the System retirement plan which is a defined benefit plan. The contribution amounts are the same, (6.25 percent employee cost and 7.55 percent employer cost) however, 5 percent of the employer amount is directed to the vendor chosen by the employee and the remaining 2.55 percent is to the Retirement System. As of December 31, 2005, twenty of the Authority s employees were participants in the State ORP and consequently the related payments are not material. The Authority is the non-operating owner (one-third share) of SCE&G s V.C. Summer Nuclear Station. As such the Authority is responsible for funding its share of pension requirements for the nuclear station personnel in accordance with FASB Statement No. 87, Employers Accounting for Pensions (FASB 87). The established pension plan generates earnings which are shared proportionately and used to reduce the allocated funding. As of December 31, 2005 and 2004, the Authority had over-funded its share of the plan FASB 87 requirements due to these earnings in the amount of $10.2 million and $9.7 million, respectively. This receivable will be applied to future years as additional expenditures are required to meet the Authority s funding obligation. The pre-funded amounts are in Other within Deferred debits and other noncurrent assets on the balance sheet. The Authority also provides compensation benefits to certain employees designated by management and the Board of Directors under Supplemental Executive Retirement Plans (SERP). The plans are administered by the Authority as a single employer defined benefit pension plan. Benefits are established and may be amended by the Authority s Board of Directors and include compensation for a specified number of years and life insurance benefits. The cost of these benefits is actuarially determined annually and is paid by the Authority on a pay-as-you-go basis. The cost for 2005 and 2004 was approximately $3.0 million and $2.2 million, respectively. The accrued liability at December 31, 2005 and 2004 was approximately $8.0 million and $8.4 million, respectively. Note 11 Other Postretirement Benefits: The South Carolina Retirement System provides certain health, dental, and life insurance benefits for retired employees of the Authority. Substantially all of the Authority s employees may become eligible for these benefits if they retire at any age with 28 years of service or at age 60 with at least 20 years of service. Currently, approximately 467 retirees meet these requirements. The cost of the health, dental and life insurance benefits are recognized as expense as the premiums are paid. For each of Appendix 1 the years ended December 31, 2005 and 2004, these costs totaled approximately $2.0 million and $1.9 million, respectively. The Authority is the non-operating owner (one-third share) of SCE&G s V. C. Summer Nuclear Station. As such the Authority is responsible for funding its share of other post employment benefits costs for the station s employees. The liability balances as of December 31, 2005 and 2004 were approximately $7.3 million and $7.0 million, respectively. During their first 10 years of service, full-time employees can earn up to 15 days vacation leave per year. After 10 years of service, employees earn an additional day of vacation leave for each year of service over 10 until they reach the maximum of 25 days per year. Employees earn annually two hours per pay period, plus twenty additional hours at year-end for sick leave. Employees may carry forward up to 45 days of vacation leave and 180 days of sick leave from one calendar year to the next. Upon termination, the Authority pays employees for accumulated vacation leave at the pay rate then in effect. In addition, the Authority pays employees upon retirement 20 percent of their accumulated sick leave at the pay rate then in effect. Note 12 Credit Risk and Major Customers: Sales to two major customers for the years ended December 31, 2005 and 2004 were as follows: (Thousands) Central (including Saluda) $ 676,000 $ 583,000 Alumax $ 143,000 $ 118,000 No other customer accounted for more than 10 percent of the Authority s sales for either of the years ended December 31, 2005 or The Authority maintains an allowance for uncollectible accounts based upon the expected collectibility of all accounts receivable. Note 13 - Storm Damage: In August 2004, the Authority s system sustained damages from Hurricanes Charley and Gaston. As of December 31, 2005, cost estimates to repair and replace the Authority s damaged facilities are approximately $9.2 million with approximately $3.9 million representing damage to the Jefferies Steam and Hydro Generation facility and approximately $3.1 million representing damage to the East and West Dams in Pinopolis. The remaining costs reflect damage to other facilities including the transmission and distribution system, seawalls at the Wampee and Somerset properties, dump truck bodies, and costs of clearing roads and subdivisions. The Authority has filed for and anticipates disaster relief assistance from federal sources. This assistance is expected to be 75 percent of storm damage costs or approximately $6.8 million. As of December 31, 2005, O&M expense of approximately $1.7 million was recognized net of expected reimbursement. Through December 31, 2005, the Authority had not received federal assistance for either hurricane. The Authority does not expect to increase rates due to the impact of Hurricanes Charley and Gaston and foresees no measurable long-term impact on its operations or the demand for electricity by its customers. I-19

61 APPENDIX II SUMMARY OF CERTAIN PROVISIONS OF THE REVENUE OBLIGATION RESOLUTION The following statements are summaries of certain provisions of the Revenue Obligation Resolution. Except as otherwise provided in this Official Statement, terms used under this caption which are defined in the Revenue Obligation Resolution, including, but not limited to those defined hereinafter, are used herein as so defined. Certain other provisions of the Revenue Obligation Resolution are summarized under the caption SECURITY FOR THE 2006M BONDS. Compliance with the Revenue Bond Resolution The Revenue Obligation Resolution requires that the Authority comply with all the terms and provisions of the Revenue Bond Resolution. Definitions of Certain Terms Used in Revenue Obligation Resolution forth. The following words and phrases are defined in the Revenue Obligation Resolution as hereinafter set Capital Costs shall mean the Authority's costs of (i) physical construction of or acquisition of real or personal property or interests therein for any project, together with incidental costs (including legal, administrative, engineering, consulting and technical services, insurance and financing costs), working capital and reserves deemed necessary or desirable by the Authority (including but not limited to costs of supplies, fuel, fuel assemblies and components or interests therein), and other costs properly attributable thereto; (ii) all capital improvements or additions, including but not limited to, renewals or replacements of or repairs, additions, improvements, modifications or betterments to or for any project; (iii) the acquisition of any other property (tangible or intangible), capital improvements or additions, or interests therein, deemed necessary or desirable by the Authority for the conduct of its business; (iv) any other purpose for which bonds, notes or other obligations of the Authority may be issued under the Enabling Act or under other applicable State statutory provisions (whether or not also classifiable as an operating expense); and (v) the payment of principal, interest, and redemption, tender or purchase price of (a) any Obligations, Revenue Bonds, Commercial Paper or other indebtedness issued by the Authority for the payment of any of the costs specified above, including capitalized interest on such indebtedness, or (b) any indebtedness issued by the Authority to refund any indebtedness described in the preceding clause (a). Government Obligations shall mean direct obligations of, or obligations the principal of and interest on which are unconditionally guaranteed by, the United States of America. Investment Securities shall mean any of the following which at the time are legal investments under the laws of the State of South Carolina for the moneys held hereunder then proposed to be invested therein: (1) Government Obligations; (2) certificates which evidence ownership of the rights to payment of the principal of or interest on Government Obligations; (3) bonds, debentures, notes or participation certificates issued by the Bank for Cooperatives, the Federal Intermediate Credit Bank, the Federal Home Loan Bank System, the Export-Import Bank of the United States, Federal Land Bank, the Federal National Mortgage Association, the Tennessee Valley Authority, or any other agency or corporation which is or may hereafter be created by or pursuant to an Act of Congress of the United States as an agency or instrumentality thereof; (4) obligations of state and local government municipal bond issuers, provision for the payment of the principal of and interest on which shall have been made by deposit with a trustee or escrow agent of non-callable obligations described in (1), (2), or (3) of this subparagraph, the maturing principal of and interest on which when due and payable, shall provide sufficient funds to pay the principal of and interest on such obligations of state and local government municipal bond issuers (5) Public Housing Bonds, or Project Notes, fully secured by contracts with the United States; (6) repurchase agreements with banks that are members of the federal reserve system or with government bond dealers recognized as primary dealers by the Federal Reserve Bank of New York that are secured by securities described in (1) and (3) above having a current market value at least equal to one hundred two per cent (102%) of the amount of the repurchase agreement; (7) obligations of the State of South Carolina, (8) obligations of other states and investment contracts which obligations or investment contracts are rated at the time of purchase by each II-1

62 rating agency then maintaining a rating on the Obligations at the request of the Authority (each, a Rating Agency ) in one of the three highest rating categories (as determined without regard to any refinement or graduation of such rating by a numerical modifier or otherwise, a Rating Category ) of such Rating Agency; (9) deposits in interest bearing deposits or certificates of deposit or similar arrangements issued by any bank or national banking association (including the Trustee), which deposits, to the extent not insured by the Federal Deposit Insurance Corporation, shall be secured by Government Obligations (or, when the Authority s Revenue Obligations, 1999 Tax-Exempt Series A and 1999 Taxable Series B, are no longer Outstanding, obligations described in clauses (2), (3), (4) or (7) of this paragraph), having a current market value (exclusive of accrued interest) at least equal to one hundred five percent (105%) of the amount of such deposits, which Government Obligations or obligations described in clauses (2), (3), (4) or (7) of this paragraph shall have been deposited in trust by such bank or national association with the trust department of the Trustee or with a federal reserve bank or branch or, with the written approval of the Authority and the Trustee, with another bank, trust company or national banking association for the benefit of the Authority and the appropriate fund or account as collateral security for such deposits; (10) corporate securities, including commercial paper and fixed income obligations, which are, at the time of purchase, rated by a Rating Agency in one of its three highest Rating Categories for comparable types of obligations; and (11) such other investments from time to time allowed under applicable law. Obligations shall mean any obligations, issued in any form of debt, authorized by a supplemental resolution, including but not limited to bonds, notes, bond anticipation notes, and Qualified Swaps, which are delivered under the Revenue Obligation Resolution. Operation and Maintenance Expenses shall mean the Authority's expenses of operating the System, including, but not limited to, all costs of purchased power, operation, maintenance, generation, production, transmission, distribution, repairs, replacements, engineering, transportation, administration and general, audit, legal, financial, pension, retirement, health, hospitalization, insurance, taxes and any other expenses actually paid or accrued, of the Authority applicable to the System, as recorded on its books pursuant to generally accepted accounting principles, subject to the limitations with respect to take or pay contracts as set forth under Take or Pay Contracts. Operation and Maintenance Expenses shall not include (1) any costs or expenses for new construction, (2) charges for depreciation, (3) voluntary payments in lieu of taxes or (4) any taxes or tax payments now or hereafter required to be made to the State or any political subdivisions only out of surplus revenues, for example, payments required by Code Sections , (2) and (3), and , Code of Laws of South Carolina Permitted Investments shall mean the obligations referred to in (1), (2), (3) and (4) of the definition of the term "Investment Securities". Qualified Swap shall mean, to the extent from time to time permitted by law, with respect to Obligations, any financial arrangement (i) which is entered into by the Authority with an entity that is a Qualified Swap Provider at the time the arrangement is entered into, (ii) which is a cap, floor or collar; forward rate; future rate; swap (such swap may be based on an amount equal either to the principal amount of such Obligations of the Authority as may be designated or a notional principal amount relating to all or a portion of the principal amount of such Obligations); asset, index, price or market-linked transaction or agreement; other exchange or rate protection transaction agreement; other similar transaction (however designated); or any combination thereof; or any option with respect thereto, executed by the Authority for the purpose of moderating interest rate fluctuations or otherwise, and (iii) which has been designated in writing to the Trustee by the Authority as a Qualified Swap with respect to such Obligations. Qualified Swap Provider shall mean an entity whose senior long term obligations, other senior unsecured long term obligations or claims paying ability, or whose payment obligations under an interest rate exchange agreement are guaranteed by an entity whose senior long term debt obligations, other senior unsecured long term obligations or claims paying ability, are rated either (i) at least as high as the third highest Rating Category of each Rating Agency, but in no event lower than any Rating Category designated by each such Rating Agency for the Obligations subject to such Qualified Swap, or (ii) any such lower rating categories which each such Rating Agency indicates in writing to the Authority and the Trustee will not, by itself, result in a reduction or withdrawal of its rating on the Outstanding Obligations subject to such Qualified Swap that is in effect prior to entering into such Qualified Swap. II-2

63 Revenues shall mean all the revenues, income, profits, tolls, rents, charges and returns of the Authority derived from its ownership or operation of the System, including the proceeds of any insurance covering business interruption loss relating to the System, but excluding other insurance proceeds and proceeds realized from the sale of properties of the System pursuant to the provisions of the Revenue Bond Resolution and customer deposits. System The Authority's System, as defined in the Revenue Obligation Resolution, consists generally of (a) facilities for the purpose of acquiring, controlling, storing, preserving, treating, distributing and selling water for (i) navigation, power, irrigation, reclamation, or sale to residential, commercial, agricultural or industrial customers or other governmental entities; and (b) plants, works, structures, facilities and equipment for the generation, manufacture, transmission or distribution of water power and electric power and energy, and of any other forms of power and energy when authorized by the Enabling Act. The System shall not include separate projects established by the Authority for any corporate purpose of the Authority other than those projects and purposes described hereinabove, nor separate systems described under Separate Systems. Revenue Fund The Revenue Obligation Resolution continues, for so long as any of the Revenue Obligations are Outstanding, the Revenue Fund. The Revenue Fund shall be held in trust and administered by the Authority. The Authority covenants and agrees in the Revenue Obligation Resolution to pay into the Revenue Fund, as promptly as practical after the receipt thereof, all Revenues. Funds and Accounts For the purpose of providing for the payment of the principal of, premium, if any, and interest on the Revenue Obligations, the Revenue Obligation Resolution creates a Revenue Obligation Fund. Payments into the Revenue Obligation Fund shall be made after payments with respect to outstanding Revenue Bonds pursuant to the Revenue Bond Resolution, but prior to the payments required to be made from, or retained in, the Revenue Fund to cover the cost of operation and maintenance of the System and the payments required to be made into the Lease Fund and the Capital Improvement Fund. Order of Payments From Revenue Fund While Revenue Bonds are outstanding; moneys shall be disbursed by the Authority from the Revenue Fund in the following order: 1. Revenue Bond Fund: To pay monthly to the Revenue Bond Fund Trustee the Revenue Bond Fund Payments. 2. Revenue Obligation Fund: To pay when due to the Trustee the Revenue Obligation Fund Payments. 3. Operating and Maintenance: To pay expenses of operation and maintenance. 4. Lease Fund: To pay monthly to the Lease Fund a proportionate amount of the next due lease payments. 5. Capital Improvement Fund: To pay during each Fiscal Year into the Capital Improvement Fund amounts at least equal to the Minimum Capital Improvement Requirement. II-3

64 Order of Payment after Revenue Bonds are No Longer Outstanding Under the Revenue Obligation Resolution, after all Revenue Bonds have been retired, or provision has been made therefor, moneys shall then be disbursed by the Authority from the Revenue Fund in the following order: 1. Revenue Obligation Fund: To pay when due to the Trustee the Revenue Obligation Fund Payments. 2. Operating and Maintenance: To pay expense of operation and maintenance. 3. Lease Fund: To pay when due into the Lease Fund an amount equal to the next due lease payments. 4. Capital Improvement Fund: To pay during each Fiscal Year into the Capital Improvement Fund amounts at least equal to the Minimum Capital Improvement Requirement. ^ Any moneys remaining in the Revenue Fund each month after making the payments referenced above may be used by the Authority for any corporate purpose of the Authority. Certain Moneys Not Required to be Deposited in Revenue Fund Neither the Revenue Bond Resolution nor the Revenue Obligation Resolution requires the deposit into the Revenue Fund of any of the revenues, income, receipts, profits or other moneys of the Authority derived by the Authority through the ownership or operation of any separate system described under the section Separate System or through the ownership or operation of any separate project referred to under the section System. Authorization of Revenue Obligations At any time one or more series of Revenue Obligations may be issued pursuant to the Revenue Obligation Resolution, upon the terms set forth in a Series Resolution, for any corporate purpose of the Authority, including the refunding or purchase of Revenue Obligations or Revenue Bonds, provided there is no default under the Revenue Obligation Resolution or the Revenue Bond Resolution. Separate Systems The System shall not include (i) any facilities for the purpose of providing water for sale to residential, commercial, agricultural or industrial customers or other governmental entities, or (ii) any facilities for the generation of any form of power and energy, or for the transmission and distribution of any form of power and energy, and any incidental properties constructed, acquired or leased in connection therewith, constructed or acquired by the Authority as a separate system, and if constructed or acquired with the proceeds of sale of bonds or other evidences of indebtedness, which bonds or other evidences of indebtedness are payable solely from the revenues or other income derived from the ownership or operation of such separate utility system, and may be further secured by a pledge of Revenues junior and subordinate to the pledge securing the Revenue Bonds and payable therefrom, but only after the revenues and other income derived from the ownership or operation of such separate utility system and pledged to the payment of such bonds or other indebtedness are so applied in accordance with the proceedings providing for the issuance of such bonds or other indebtedness. II-4

65 Junior Lien Obligations Nothing in the Revenue Obligation Resolution shall prevent the Authority from issuing bonds, notes, bond anticipation notes, warrants, certificates or other obligations or evidences of indebtedness the payment of which shall be made from the proceeds of Revenue Obligations or other indebtedness of the Authority or from Revenues, and if payable from Revenues shall be made junior and subordinate to the payment of the Revenue Obligations. The Authority may create special funds to provide for the payment of such obligations, payments to which shall be made after payments to the Revenue Obligation Fund, and may, if the Authority so provides, but need not be, junior to the payments into the Lease Fund. Insurance The Revenue Bond Resolution and the Revenue Obligation Resolution require the Authority to insure such of its various properties as are usually insured by utilities owning like properties in similar amounts and coverages, with insurance companies, and to carry liability insurance in reasonable amounts. Sale, Lease or Other Disposition of Properties Subject to the next sentence, the Authority may sell, lease, or otherwise dispose of any part of its properties on such terms and conditions as may be prescribed by its Board of Directors and, so long as any Revenue Bonds are Outstanding, upon compliance with any additional requirements set forth in the Revenue Bond Resolution. The Authority shall not take any action described in the preceding sentence unless, in the judgment of the Authority's Board of Directors, such action is desirable in the conduct of the Authority's business and does not materially impair the Authority's ability to comply with the rate covenant provisions of the Revenue Obligation Resolution. Take or Pay Contracts The Revenue Obligation Resolution does not prohibit the Authority from entering into take or pay contracts, including take or pay contracts with a separate system described under section Separate Systems, to purchase power under conditions whereby payments the Authority is required to make may be calculated, in whole or in part, on the basis of power which the Authority does not purchase, require or obtain for whatever reasons. However, payments made by the Authority under such a take or pay contract for power not available for any reason other than an emergency or forced outage lasting not more than one year or normal and regularly scheduled maintenance outage may not be treated as Operation and Maintenance Expenses. Capital Improvement Fund The Revenue Obligation Resolution requires the deposit annually into the Capital Improvement Fund of an amount at least equal to the Minimum Capital Improvement Requirement defined as follows: an amount, which, together with the amounts deposited in the Capital Improvement Fund in the two immediately preceding Fiscal Years, will be at least equal to 8% of the revenues required by the Revenue Obligation Resolution to be paid into the Revenue Fund in the three immediately preceding Fiscal Years. Certain payments not made into the Capital Improvement Fund may be considered as a payment towards fulfillment of the Minimum Capital Improvement Requirement. The moneys on deposit in the Capital Improvement Fund shall be used, so long as any Revenue Bonds are outstanding, to make up any deficiency in the Interest Account, Principal Account and Bond Retirement Account in the Revenue Bond Fund established by the Revenue Bond Resolution to the extent that moneys in the Revenue Fund shall not be available therefore and, to the extent not required to make up any such deficiency, shall be used solely to make renewals, replacements, extensions, additions, betterments and other capital additions to the System and for the acquisition of material, equipment and supplies for such renewals, replacements, extensions, betterments and other capital additions. After the Revenue Bonds are no longer outstanding, the moneys on deposit in the Capital Improvement Fund shall be used solely to pay Capital Costs. II-5

66 Lease Fund The Authority covenants that there will be paid monthly into the Lease Fund the amounts necessary to make payments under leases of properties or facilities leased to the Authority and used for the purpose of generating, transmitting and distributing all forms of power and energy. Events of Default and Remedies Under the Revenue Obligation Resolution A happening of one or more of the following constitutes an Event of Default under the Revenue Obligation Resolution: (a) default in the due and punctual payment of any interest on any Revenue Obligation which shall continue for a period of 30 days; or (b) default in the due and punctual payment of the principal of any Revenue Obligation, whether at the stated maturity thereof, at the mandatory redemption date, at the redemption date or upon declaration; or (c) the Authority shall violate or fail to perform any of its covenants or agreements contained in the Revenue Obligation Resolution for 90 days after written notice of default is given to it by the Bond Fund Trustee or by the holder of any Revenue Obligation; or (d) a default shall have occurred in respect of any bond, debenture, note or other evidence of indebtedness of the Authority, or in respect of any obligations of the Authority under any financing lease, whether now outstanding or existing or issued or otherwise undertaken hereafter, or under any indenture, resolution, lease or other agreement or instrument under which any such bond, debenture, note or other evidence of indebtedness or any such lease obligation has been or may be issued or by which any of the foregoing is or may be governed or evidenced, which default shall have resulted in the principal amount of such bond, debenture, note or other evidence of indebtedness or lease obligation becoming due and payable prior to its stated maturity or which default shall have been a default in the payment of principal when due and payable; or (e) a decree or order by a court having jurisdiction in the premises shall have been entered judging the Authority as bankrupt or insolvent, or approving as properly filed a petition seeking reorganization or arrangement of the Authority under the Federal bankruptcy laws or any similar applicable Federal or South Carolina law, and such decree or order shall have continued undischarged or unstayed for a period of forty (40) days; or a decree or order of a court having jurisdiction in the premises for the appointment of a receiver or liquidator or trustee or assignee in bankruptcy or insolvency of the Authority or any of its property, or for the winding-up or liquidation of the Authority or any of its property, shall have been undischarged and unstayed for a period of sixty (60) days; or (f) the Authority shall institute proceedings to be adjudicated a voluntary bankrupt, or shall consent to the filing of a bankruptcy proceeding against it, or shall file a petition or answer or consent seeking reorganization or arrangement under the Federal bankruptcy laws or any similar applicable Federal or South Carolina law, or shall consent to the filing of any such petition, or shall consent to the appointment of a receiver or liquidator or trustee or assignee in bankruptcy or insolvency of the Authority or of any of its property, or shall make an assignment for the benefit of creditors, or shall admit in writing its insolvency or inability to pay its debts generally as they become due, or any action shall be taken by the Authority in furtherance of any of the foregoing aforesaid purposes; or (g) a default shall occur under the Revenue Bond Resolution. If an Event of Default has occurred, and shall not have been remedied, the Trustee or the holders of not less than 25% in principal amount of the Revenue Obligations then outstanding may declare the principal of all II-6

67 Revenue Obligations and the interest accrued thereon to be immediately due and payable, but such declaration may be rescinded under certain circumstances. After the occurrence of an Event of Default and prior to the curing of such Event of Default, the Trustee may, to the extent permitted by law, subject to the rights of the holders of outstanding Revenue Bonds, take possession and control of the System and operate and maintain the same, prescribe rates for capacity or power sold or supplied through the facilities of the System, collect the gross revenues resulting from such operation and perform all of the agreements and covenants contained in any contract which the Authority is then obligated to perform. In such event, such gross revenues, shall be applied, subject to the rights of the holders of Revenue Bonds, first to the payment of the reasonable expenses and liabilities of the Trustee and thereafter to the payment of operating expenses and principal of and interest on the Revenue Obligations. After all sums then due in respect of the Revenue Obligations have been paid, and after all Events of Default have been cured or secured, to the satisfaction of the Trustee, the Trustee is required to relinquish possession and control of the System to the Authority. At any such time the Trustee, subject to the rights of the holders of outstanding Revenue Bonds, shall be entitled to the appointment of a receiver of the business and property of the System, of the moneys, securities and funds of the Authority pledged under the Revenue Obligation Resolution, and of the Revenues, and of the income therefrom, with all such powers as the court or courts making such appointment shall confer. The Revenue Obligation Resolution empowers the Trustee to file proofs of claims for the benefit of the holders of the Revenue Obligations in bankruptcy, insolvency, or reorganization proceedings and to institute suit for the collection of sums due and unpaid in connection with the Revenue Obligations, to enforce specific performance of covenants contained in the Revenue Obligation Resolution or to obtain injunctive or other appropriate relief for the protection of the holders of the Revenue Obligations. No holder of Revenue Obligations has any right to institute suit to enforce any provision of the Revenue Obligation Resolution or the execution of any trust thereunder (except to enforce the payment of principal or interest installments as they mature), unless the Trustee has been requested by the holders of not less than 25% in principal amount of the Revenue Obligations then outstanding to exercise the powers granted it by the Revenue Obligation Resolution or to institute such suit and unless the Trustee has refused or failed, within 60 days after the receipt of such request and after having been offered adequate security and indemnity, to comply with such request. In the event the Trustee has failed or refused to comply with the aforesaid request, the Revenue Obligation Resolution provides for the creation of an Owners Committee. Modifications of the Revenue Obligation Resolution Modifications of the Revenue Obligation Resolution and of the rights and duties of the Authority and the holders of Revenue Bonds may be made with the consent of the Authority and written consent of the holders of not less than a majority of the Revenue Obligations at the time outstanding; provided that no modification shall be made which will (i) extend the fixed maturity date for the payment of any Revenue Obligation, or reduce the principal amount of or interest rate on any such Revenue Obligation or extend the time of payment of interest thereon or reduce any premium payable upon the prepayment or redemption thereof, or advance the date upon which any Revenue Obligation may first be called for redemption; or (ii) reduce the percentage of Revenue Obligations the holders of which are required to consent to any amendment to the Revenue Obligation Resolution; or (iii) give any Revenue Obligation or Revenue Obligations any preference over any other Revenue Obligation or Revenue Obligations or reduce the payments required to be made to the Revenue Obligation Fund, without the consent of the holders of all the Revenue Obligations affected thereby. II-7

68 Defeasance The obligations of the Authority under the Revenue Obligation Resolution shall be fully discharged and satisfied as to any Revenue Obligation and such Revenue Obligation shall no longer be deemed to be outstanding thereunder when payment of the principal of and the applicable redemption premium, if any, on such Revenue Obligation plus interest to the due date thereof (a) shall have been made or caused to be made in accordance with the terms thereof, or (b) shall have been provided by irrevocably depositing with the Trustee therefor in trust irrevocably appropriated and set aside exclusively for such payment (i) moneys sufficient to make such payments or (ii) Permitted Investments, maturing as to principal and interest in such amounts and at such times as will insure the availability of sufficient moneys to make such payment, and, except for the purposes of such payment, such Revenue Obligation shall no longer be secured by or entitled to the benefits of the Revenue Obligation Resolution; provided that, with respect to Revenue Obligations to be redeemed or otherwise prepaid prior to the stated maturities thereof, notice of such redemption or prepayment shall have been given or irrevocable provision shall have been made for the giving of such notice. II-8

69 APPENDIX III 134 MEETING STREET, THIRD FLOOR ( ) POST OFFICE BOX 340 ( ) CHARLESTON, SOUTH CAROLINA TELEPHONE FACSIMILE November, 2006 Board of Directors South Carolina Public Service Authority One Riverwood Drive Moncks Corner, South Carolina Re: $ South Carolina Public Service Authority Revenue Obligations, 2006 Series M We have acted as bond counsel and have examined a certified copy of the Transcript of Proceedings and other proofs submitted to us, including the Constitution and Statutes of the State of South Carolina, in relation to the issuance by South Carolina Public Service Authority (the Authority ) of the Authority's $ Revenue Obligations, 2006 Series M (the 2006 M Bonds ) consisting of $ Current Interest Bearing Bonds and $ original principal amount of Capital Appreciation Bonds. The 2006 M Bonds recite that they are issued for valid corporate purposes of the Authority under the authority of and in full compliance with the Constitution and Statutes of the State of South Carolina, including Title 58, Chapter 31, Code of Laws of South Carolina 1976, as amended, and proceedings of the Board of Directors of the Authority duly adopted, including a resolution adopted by the Board of Directors of the Authority on April 26, 1999 (as supplemented and amended from time to time, the Revenue Obligation Resolution ). All capitalized terms used herein and not defined shall have the meaning ascribed to such terms in the Revenue Obligation Resolution. As to questions of fact material to our opinion, we have relied upon representations of the Authority contained in the Revenue Obligation Resolution and in the certified Transcript of Proceedings and other certifications of public officials and others furnished to us, without undertaking to verify the same by independent investigation. Based upon the foregoing, we are of the opinion, under existing statutes, regulations and court decisions, as follows: 1. The 2006 M Bonds have been authorized and issued in accordance with the Constitution and statutes of the State of South Carolina and constitute valid and legally binding special obligations of the Authority payable solely from and secured by a lien upon and pledge of the Revenue Fund and the revenues of the Authority's System and other monies paid into the Revenue Fund (collectively, the Revenues ), all as set forth and III-1

70 Board of Directors November, 2006 Page 2 provided in the Revenue Obligation Resolution, on a parity with bonds heretofore and hereafter issued by the Authority pursuant to the Revenue Obligation Resolution on a parity with the 2006 M Bonds, but junior, subordinate and inferior to the lien upon and pledge of Revenues securing the payments required to be made into the Revenue Bond Fund and the accounts therein, established for the payment of the Revenue Bonds pursuant to the provision of the Revenue Bond Resolution. 2. Interest on the 2006 M Bonds is excludable from gross income for federal income tax purposes and is not an item of tax preference for purposes of the federal alternative minimum tax imposed on individuals and corporations; it should be noted, however, that for the purpose of computing the alternative minimum tax imposed on certain corporations (as defined for federal income tax purposes), such interest is taken into account in determining adjusted current earnings. The opinion set forth in the preceding sentence is subject to the condition that the Authority comply with all requirements of the Internal Revenue Code of 1986, as amended, that must be satisfied subsequent to the issuance of the 2006 M Bonds in order that interest thereon be (or continue to be) excluded from gross income for federal income tax purposes. Failure to comply with certain of such requirements may cause interest on the 2006 M Bonds to be included in gross income for federal income tax purposes retroactive to the date of issuance of the 2006 M Bonds. We express no opinion regarding other federal tax consequences arising with respect to the 2006 M Bonds. 3. The 2006 M Bonds and the interest thereon are exempt from all state, county, school district, municipal, and all other taxes or assessments of the State of South Carolina, except inheritance, estate, transfer or certain franchise taxes. We express no opinion regarding the accuracy, completeness, or sufficiency of any offering material relating to the 2006 M Bonds. Furthermore, we express no opinion regarding federal tax consequences arising with respect to the 2006 M Bonds, other than as expressly set forth herein. It is to be understood that the rights of the owners of the 2006 M Bonds and the enforceability of the 2006 M Bonds may be limited by bankruptcy, insolvency, reorganization, moratorium and other similar laws affecting creditors' rights generally and by equitable principles, whether considered at law or in equity. Very truly yours, III-2